Shale gas and non-aqueous fracturing fluids: Opportunities and challenges for supercritical CO2

Middleton, Richard S.; Carey, J. William; Currier, Robert P.; Hyman, Jeffrey D.; Kang, Qinjun; Karra, Satish; Jiménez‐Martínez, Joaquín; Porter, Mark L.; Viswanathan, Hari

doi:10.1016/j.apenergy.2015.03.023

Cited by 692 publications

(292 citation statements)

References 75 publications

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“…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: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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

et al. 2018

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“…When shale samples are saturated in gaseous/super-critical CO2 with the medium of fresh water, clays in the rock absorb water resulting in the shale swelling, which causes the decrease of strength and Young's modulus [39]. According to Heller and Zoback [40] and Luo et al [41], shale gas, which exists in natural fractures, porous matrices and kerogen, is easier to be replaced by CO2 as CO2 has better adsorption ability in shale [42]. Therefore, the adsorption of CO2 in shale samples will also cause shale swelling and strength decrease [43].…”

Section: Effects Of Co2-water-rock Interaction On Mechanical Behaviorsmentioning

confidence: 99%

Experimental Investigation of Mechanical Properties of Black Shales after CO<sub>2</sub>-Water-Rock Interaction

Lyu¹,

Ranjith²,

Long³

et al. 2016

Preprint

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Abstract:The effects of CO2-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO2 in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO2. According to the experimental results, the values of UCS, Young's modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO2. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young's modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young's modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO2, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO2). SC-CO2 causes a greater reduction of shale's mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous /super-critical CO2. The EDS results show that CO2-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation.

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“…In addition, the expansion of gas phase after treatment helps to recover the introduced liquid phase into the formation. CO 2 gas is more beneficial due to relatively high adsorption ability as compared to CH 4 , which is a good aspect for releasing the adsorbed gas and underground carbon sequestration [5,9,[12][13][14][15][16][17].…”

Section: Introductionmentioning

confidence: 99%

“…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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Shale gas and non-aqueous fracturing fluids: Opportunities and challenges for supercritical CO2

Cited by 692 publications

References 75 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

Experimental Investigation of Mechanical Properties of Black Shales after CO<sub>2</sub>-Water-Rock Interaction

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

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