Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations

Makhanov, K.; Habibi, Ali; Dehghanpour, Hassan; Kuru, Ergün

doi:10.1016/j.juogr.2014.04.001

Cited by 241 publications

(147 citation statements)

References 37 publications

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“…By keeping all the other parameters fixed, the foam consistency index (K) and exponent (n) in the power law model (Equation (1)) varied as a function of dimensionless pressure. Based on individual investigations of these parameters, it was found that both indices K and n are quadratically related to dimensionless pressure as shown in Equations (8) and (9). Figure 7 presents a plot of both measured and predicted values of indices K and n versus dimensionless pressure.…”

Section: Effect Of Pressurementioning

confidence: 99%

“…Hydraulic fracturing of shales is a technique that is widely known to unlock these stored reserves [3] and the fracturing fluids that are commonly used are polymer-based aqueous solutions. However, the application of polymers can plug the nanopores, which becomes a crucial issue [4][5][6][7][8][9]. Moreover, the fracturing process requires a high amount of fresh water during its application, it is susceptible to formation damage in water-sensitive regions, and it provides a reduction in liquid recovery [7,9].…”

Section: Introductionmentioning

confidence: 99%

“…However, the application of polymers can plug the nanopores, which becomes a crucial issue [4][5][6][7][8][9]. Moreover, the fracturing process requires a high amount of fresh water during its application, it is susceptible to formation damage in water-sensitive regions, and it provides a reduction in liquid recovery [7,9]. Other methods have been considered as alternatives to enhancing gas production from shales: gas fracking or pneumatic fracking.…”

Section: Introductionmentioning

confidence: 99%

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Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

et al. 2018

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High-quality supercritical CO 2 (sCO 2 ) foam as a fracturing fluid is considered ideal for fracturing shale gas reservoirs. The apparent viscosity of the fracturing fluid holds an important role and governs the efficiency of the fracturing process. In this study, the viscosity of sCO 2 foam and its empirical correlations are presented as a function of temperature, pressure, and shear rate. A series of experiments were performed to investigate the effect of temperature, pressure, and shear rate on the apparent viscosity of sCO 2 foam generated by a widely used mixed surfactant system. An advanced high pressure, high temperature (HPHT) foam rheometer was used to measure the apparent viscosity of the foam over a wide range of reservoir temperatures (40-120 • C), pressures (1000-2500 psi), and shear rates (10-500 s −1 ). A well-known power law model was modified to accommodate the individual and combined effect of temperature, pressure, and shear rate on the apparent viscosity of the foam. Flow indices of the power law were found to be a function of temperature, pressure, and shear rate. Nonlinear regression was also performed on the foam apparent viscosity data to develop these correlations. The newly developed correlations provide an accurate prediction of the foam's apparent viscosity under different fracturing conditions. These correlations can be helpful for evaluating foam-fracturing efficiency by incorporating them into a fracturing simulator.

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Section: Effect Of Pressurementioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

et al. 2018

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“…Hu et al (2012) and Makhanov et al (2014) suggested that these parameters should meet the following equation:…”

Section: Basic Representative Elementary Structurementioning

confidence: 99%

Spontaneous imbibition in asymmetric branch-like throat structures in unconventional reservoirs

Shen

et al. 2017

Journal of Natural Gas Science and Engineering

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a b s t r a c tUnconventional reservoirs, especially shale plays, have abundant micro-nano pores. Large volume water was injected into the reservoir during hydraulic fracturing. Fracturing fluid can displace gas in pore spaces spontaneously, called spontaneous imbibition (SI), which has significant effects on the gas production after hydraulic fracturing. Throat structure in matrix is one of the key factors to influence SI process. In this work, at first, complex pore space is simplified as a spatial self-similar branch-like structure composed of several asymmetric sub-throats. Then, within asymmetric branch structure, the imbibition process is calculated by a newly established mathematical model, and the influence of both pore structure and fluid characteristics, including contract angle, viscosity, surface tension, are discussed. Finally, some lab experiments, especially SI tests, are included on shale and sandstone core plugs to verify our model. Results show that the coherence in wettability between the reservoir and the fracturing fluid is important to enhance the microscopic replacement effect. Pore size also has effect influence on imbibition curve. In addition, both in models and experiments, imbibition index n is useful to describe imbibition properties of rocks. In unconventional rock samples like shale, n is less than 0.4, while highpermeability sandstone, n approach to 0.5. These conclusions are useful to investigate the mechanism of spontaneous imbibition and microscopic displacement in unconventional reservoirs.

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“…When the shales are fractured using conventional aqueous based polymer solutions, the plugging of nanopores takes place [6][7][8][9][10][11]. These conventional fracturing fluids need high amount of fresh water, increases the formation damage especially in the water sensitive zones and decreases the liquid recovery [9,11]. Gas fracking or pneumatic fracking is one of the alternative and highly beneficial methods for enhancing gas production from shales.…”

Section: Introductionmentioning

confidence: 99%

Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

et al. 2017

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High quality polymer free CO 2 foam possesses unique properties that make it an ideal fluid for fracturing unconventional shales. In this paper, the viscosity of polymer free fracturing foam and its empirical correlations at high pressure high temperature (HPHT) as a function of surfactant concentration, salinity, and shear rate are presented. Foams were generated using a widely-used surfactant, i.e., alpha olefin sulfonate (AOS) in the presence of brine and a stabilizer at HPHT. Pressurize foam rheometer was used to find out the viscosity of CO 2 foams at different surfactant concentration (0.25-1 wt %) and salinity (0.5-8 wt %) over a wide range of shear rate (10-500 s −1 ) at 1500 psi and 80 • C. Experimental results concluded that foam apparent viscosity increases noticeably until the surfactant concentration of 0.5 wt %, whereas, the increment in salinity provided a continuous increase in foam apparent viscosity. Nonlinear regression was performed on experimental data and empirical correlations were developed. Power law model for foam viscosity was modified to accommodate for the effect of shear rate, surfactant concentration, and salinity. Power law indices (K and n) were found to be a strong function of surfactant concentration and salinity. The new correlations accurately predict the foam apparent viscosity under various stimulation scenarios and these can be used for fracture simulation modeling.

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Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations

Cited by 241 publications

References 37 publications

Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

Spontaneous imbibition in asymmetric branch-like throat structures in unconventional reservoirs

Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

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