We report a study on the mechanical properties of lamellae-forming glassy−semicrystalline block copolymers composed of poly(cyclohexylethylene) (C) and polyethylene (E). Tensile properties of polydomain CEC, ECEC, CECEC, and ECECE block copolymers, and blends of these materials, reveal a critical dependence on the connectivity of the semicrystalline E blocks. A molecular parameter directly related to the fraction of bridging E blocks is identified, which captures the fracture behavior of C/E block copolymers over a range of chain architectures. Tensile testing and small-angle X-ray scattering (SAXS) experiments on aligned block copolymers reveal the role of bridging in the glassy C block and further elucidate the mechanisms that govern the deformation of microphase-separated lamellar domains and macroscopic fracture in glassy−semicrystalline block copolymers.
High Viscosity Friction Reducers (HVFRs) are often employed in hydraulic fracturing fluids to increase the proppant carrying capacity of slickwater fluids. However, it has been widely reported that the performance of HVFR fluids drops precipitously with even small amounts of salt. This study explores and reports the use of surfactants to alleviate the loss of performance of HVFR fluids due to salinity in the mix water. Fracturing fluids were prepared in the laboratory by mixing the HVFR at concentrations between 2 and 8 gal/1,000 gal with and without surfactant formulations. The viscosities of the fluids were measured on a TA Instruments DHR-3 rheometer using a concentric cylinder geometry. Both anionic and cationic HVFRs were tested with various surfactants. As expected, we observed that HVFR fluids display dramatic loss of viscosity with the addition of as little as 1% salt to the mix water. However, certain surfactant formulations were found to provide a significant boost in viscosity of HVFR fluids in brines over a wide range of shear rates. Increases in viscosity by a factor of as much as 10 times were observed, particularly at low shear rates. The ability of the surfactant formulations to enhance fluid viscosity was observed in both monovalent and divalent model brines, as well as brines that mimicked field produced water compositions. In addition, measurements were also performed in a slot flow device to determine if the results from the rheometer translated to proppant transport characteristics of the fluids. The slot flow results were found to correlate well with fluid viscosity measurements. The fluids containing the surfactant formulation transported nearly 4 times as much proppant as fluids not containing surfactant through a 2.5 ft. long rectangular slot of 0.5 in. thickness at a proppant concentration of 2 lb/gal. An obvious benefit of the approach proposed in this study is that it can enable the use of HVFR fluids in recycled and produced waters, providing both cost and sustainability benefits. Secondly, these surfactant formulations can reduce the amount of HVFR required to obtain a certain target viscosity in brine, thereby reducing the likelihood and potential severity of formation damage from HVFR residue.
SynopsisThe transport of gaseous ethylene oxide (EtO) in several polymer f i l m s is studied using the carrier gas method of measurement. Permeability, solubility, and diffusion coefficients describing ethylene oxide (EtO) transport in polypropylene, polyvinylchloride, Teflon-FEP copolymer, and polyethylene films have been obtained over a 30 Celsius degree range at a low concentration of EtO using the carrier gas method of measurement. The results indicate that the diffusion of EtO in polyethylene is independent of penetrant concentration over the range of concentrations used.However, concentration-independent d i e o n could not be verified directly for the other films studied. Two different techniques of determining difwion coefficients were used, and within the precision of the data both yield the same result. An excess enthaIpy of solution for the solubility of EtO in Teflon-FEP copolymer was calculated, an observation that suggests that dual-mode sorption may be taking place.
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures. This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties -such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young's modulus -on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design which have improved productivity in these reservoirs. However, further advances in treatment design require a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and interaction with natural fractures. This paper investigates the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters, with a focus on proppant and fluid selection. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model, with the Unconventional Production Model is presented. This workflow has shown qualitative consistency with real production data. In this paper we applied the workflow on a realistic reservoir with characteristics from the Marcellus play, and then studied the relation between production and treatment design parameters such as proppant size, proppant concentration, the treatment volume of the treatment, fracturing fluid viscosity, pumping rate and proppant injection sequence. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fluid viscosity for every parameter. More than four hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. The behaviors observed confirm several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. Another key finding is that the optimum fluid viscosity increases with treatment volume, and decreases when pumping rate increases.
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