Experimental study on the rheology of CO2 viscoelastic surfactant foam fracturing fluid

Sun, Xin; Liang, Xiaobing; Wang, Shuzhong; Lu, Yi

doi:10.1016/j.petrol.2014.04.017

Cited by 101 publications

(37 citation statements)

References 20 publications

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“…The gas phase utilized was purified carbon dioxide (i.e., 99.99% pure). At the experimental conditions, CO 2 is in a supercritical form where it shows unique physical properties and holds both diffusivity of gas as well as solvating power of liquids [18,30].…”

Section: Experimental Methodologymentioning

confidence: 99%

“…Other methods have been considered as alternatives to enhancing gas production from shales: gas fracking or pneumatic fracking. This application has several advantages efficiency is reliant on the non-Newtonian behavior of foam [30,31]. There are different models to describe the flow behavior of foam.…”

Section: Introductionmentioning

confidence: 99%

“…There are different models to describe the flow behavior of foam. The most widely used model is Ostwald-de Waele or power law model [5,30,[32][33][34][35][36][37] and it is mathematically represented by Equation (1):…”

Section: Introductionmentioning

confidence: 99%

“…The apparent viscosity of foam is a strong function of various process variables, which include reservoir temperature, reservoir pressure, foam quality, salinity, shear rate, and chemical additives and their concentrations [5,30,31], and it is important to conduct controlled experiments in order to study the effect of each process variable.…”

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: Experimental Methodologymentioning

confidence: 99%

Section: Introductionmentioning

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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“…The system software collected the data of differential pressure (∆P) at different tested shear rate. Hagen-Poiseulle equation was then used to calculate the apparent viscosity of bulk foam and is represented as Equation (2) below [20,38,42,43].…”

Section: Experimental Methodologymentioning

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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Variations and model of the rheological parameters of low damage BCG − CO₂ fracturing fluid

Luo

Pan

et al. 2020

Can J Chem Eng

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A BCG − CO 2 fracturing fluid composed of a new thickener and CO 2 causes low amounts of formation damage, and it can be used to stimulate low-permeability gas reservoirs with water sensitivity. However, at present the rheological properties of this foam fracturing fluid are unclear, which has limited its field application to some degree. The main purpose of this study was to ascertain the rheological parameters and a model of the BCG − CO 2 fracturing fluid. The rheological properties of the BCG − CO 2 fracturing fluid were evaluated by using a foam rheological test system. The unfoamed condition test results showed that when the shear rate was lower than 1000 s −1 , the effective viscosity exhibited a rapid decreasing trend. The effective viscosity of the BCG − CO 2 fracturing fluid was 4 to 26 mPa Á s under foamed conditions. The comparison results showed that the viscosity of the BCG − CO 2 foam was suitable as a low damage fracturing fluid. The measured data were fitted using the H-B and power law models in this study. The power law model, by contrast, was fit for describing the relationship between shear rate and shear stress. The foamed condition rheological index n 0 first decreased and then increased with increasing foam quality, and the rheological coefficient k 0 first increased and then decreased with increasing foam quality. For the different foam qualities, the rheological index n 0 first increased and then decreased with increasing temperature. The rheological coefficient k 0 showed a decreasing trend with increasing temperature. When an exponential function, in which the foam quality and temperature were independent, was used for fitting, it was not accurate in predicting the rheological properties. The fitting results based on a quadratic polynomial surface model were better. The average calculation errors of the rheological parameters were all less than 3.32%. The findings of this study can help develop a better understanding of the heat transfer and flow coupling process in wellbore and fracture in fracturing treatment.

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Experimental study on the rheology of CO2 viscoelastic surfactant foam fracturing fluid

Cited by 101 publications

References 20 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

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

Variations and model of the rheological parameters of low damage BCG − CO₂ fracturing fluid

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Experimental study on the rheology of CO2 viscoelastic surfactant foam fracturing fluid

Cited by 101 publications

References 20 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

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

Variations and model of the rheological parameters of low damage BCG − CO2 fracturing fluid

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Variations and model of the rheological parameters of low damage BCG − CO₂ fracturing fluid