Numerical simulation of chemical potential dominated fracturing fluid flowback in hydraulically fractured shale gas reservoirs

Wang, Fei; Pan, Ziqing

doi:10.1016/s1876-3804(16)30123-9

Cited by 19 publications

(12 citation statements)

References 22 publications

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“…In eq 5, q l fm stands for the water/gas flux between f and m (g/cm 3 ·s), which can be calculated by the following equationwhere α 2 stands for the shape factor between f and m (cm –2 ), proposed by Kazemi et al, 59 p l m and p c,l m stand for the water/gas pressure (10 –1 MPa) and capillary force (10 –1 MPa) in m, respectively, and p π , described by Wang and Pan, 42 is the osmotic pressure (10 –1 MPa) for water, which can be defined aswhere λ is the membrane efficiency characterizing the capacity of the clay membrane to allow water molecule pass through; x f stands for the molar fraction of the water molecule in the fracturing fluid, while x m represents the molar fraction of the water molecule in the formation brine.…”

Section: Mathematical Modelmentioning

confidence: 99%

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Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Liu

Yandong

et al. 2019

ACS Omega

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Fracture characterization is necessary to evaluate fracturing operations and forecast well performance. However, it is challenging to quantitatively characterize the complex fracture network in shale gas reservoirs because of the unknown density and reactivation of natural fractures. The flowback water transients can provide useful information about the complexity of the fracture network after the fracturing operations. In this paper, a mathematical model for modeling fracturing fluid flowback of hydraulically fractured shale gas wells is established. This proposed model characterizes the flow of water and gas in a hydraulic fracture-induced natural fracture–shale matrix system. Hydraulic, capillary, and osmotic convections; gas adsorption; and natural fracture closure are considered in this model. Flowback simulation of a hydraulically fractured shale gas well is conducted using the developed numerical simulator, and the water/gas transients between hydraulic fractures, natural fractures, and matrix are obtained. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China, are used for comparison of the flowback data with the model results. The good match of the two water transients provides a group of fracture network parameters, that is, the effective length and conductivity of main hydraulic fractures and the density of induced natural fractures. The proposed model for describing the flowback process and its meaningful relationship with the fracture–network complexity provides an alternative approach for post-stimulation evaluation.

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Section: Mathematical Modelmentioning

confidence: 99%

“…In 2016, Fakcharoenphol et al 41 simulated fracturing fluid flowback to investigate how shut-in affects gas produced and water recovery. In 2016, Wang and Pan 42 proposed a chemical potential dominant flowback model in shale gas reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Liu

Yandong

et al. 2019

ACS Omega

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“…During the drilling process of shale formation, the great salinity difference between the drilling fluid and formation water is bound to form a strong chemical potential difference, which drives the drilling fluid to migrate from the wellbore or fracture to the shale matrix. The chemical potential difference [52] is as follows:…”

Section: Chemical Potential Difference Between the Drillingmentioning

confidence: 99%

Determination of the Hydration Damage Instability Period in a Shale Borehole Wall and Its Application to a Fuling Shale Gas Reservoir in China

She

et al. 2019

Geofluids

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In reviewing Chinese shale gas reserves and national policies regarding shale gas exploitation, shale gas will be of critical importance in providing clean natural gas to China. However, compared to those in the United States, the cost of shale gas extraction and the complex problems encountered in more complex and deep drilling in China are key technologies that need to be overcome. Shale wellbore wall instability is a complex problem that often occurs during drilling. During the process of drilling in shale, the complex stress and fluid-structure interactions result in the wall rock generating a strong hydration diffusion and swelling effect, which alters the stress distribution in the rock wall and deteriorates the mechanical parameters of the rock. This results in instability damage of the shale wellbore wall. In this study, the stratigraphic stress characteristics of the Fuling Shale Gas Field were initially predicted, and the shale sample phase composition and development of bedding and microcracks were analyzed using X-ray diffraction and scanning electronic microscopy. The main driving potential difference function between the drilling fluid and shale was analyzed, and a radial adsorption diffusion model of the shale plane was established. Through a laboratory study, the space time change law of the water diffusion of the shale rock was assessed as well as the rock damage evolutionary law of the elastic modulus and compressive strength with water content. Then, combined with the shale hydration stress and strength deformation theory, a damage evolutionary equation for shale with water was derived, and the shale damage evolutionary limit equation and the method of determining the collapse cycle were established. Finally, the method was applied to the Fuling Shale Gas Field, the largest shale gas field in China, and a shale wellbore collapse cycle of approximately seven days in the field was obtained. The severity of economic loss resulting from wellbore wall instability was also determined. This study provides insight and guidance for reducing the costs of shale gas reservoir well drilling and efficient development.

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“…Fracturing practice shows that the salinity of the flowback fluid of the shale reservoir is generally high [18,19]. With the extension of the backflow time, the salinity of the flowback fluid keeps increasing, reaching up to 10 × 10 4 mg L −1 , whereas the salinity of the slick water injected during fracturing is very low (approximately 1000 mg L −1 ) [18,19]. The salt ions in the flowback fluid are mainly derived from the…”

Section: Soluble Salt Mineralsmentioning

confidence: 99%

The Influence of Injected Fluids on Microscopic Pore Structures in the Intersalt Dolomitic Shale Oil Reservoirs

Zhou

Yan

et al. 2019

Geofluids

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Given their low porosity and permeability, intersalt dolomitic shale oil reservoirs need to be developed via large-scale hydraulic fracturing to achieve economic effects. However, various lithologies and salt materials make these reservoirs vulnerable to salt mineral dissolution and recrystallization and salt plugging during development. This study investigated the variation rules of pore structures, porosity, and permeability of intersalt dolomitic shale oil reservoirs under the influence of hydraulic fracturing fluid. Correspondingly, a series of experiments (i.e., high-temperature and high-pressure soaking experiments, focused ion beam scanning helium ion microscope analyses, and porosity and pulse permeability tests) is performed on the Qian 34-10 rhythmic intersalt dolomitic shales. Results show that distilled water dissolves the salt crystals inside the matrix pores to improve the reservoir permeability. However, the distilled water-rock interaction will cause the massive migration of salt minerals. By contrast, the supercritical CO2 can disperse salt particles, dredge the channels, and enlarge pores by expansion, but it has an overall weak capability of changing the pore structure and matrix permeability. To simulate the supercritical CO2 composite fracturing, the mixed solution of supercritical CO2 and distilled water favors the salt dissolution effect in the water-based fracturing fluid and recovery enhancement by CO2. This solution can remarkably improve the reservoir porosity and permeability and avoid massive salt mineral migration and salt crystallization damage. This study is theoretically and practically important to the effective and enhanced development of intersalt dolomitic shale oil reservoirs.

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Numerical simulation of chemical potential dominated fracturing fluid flowback in hydraulically fractured shale gas reservoirs

Cited by 19 publications

References 22 publications

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Determination of the Hydration Damage Instability Period in a Shale Borehole Wall and Its Application to a Fuling Shale Gas Reservoir in China

The Influence of Injected Fluids on Microscopic Pore Structures in the Intersalt Dolomitic Shale Oil Reservoirs

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