Publications by Year: 2015

2015
E. Ortega, Torres-Verdín, C., and Preeg, W. E., “2D inversion-based interpretation of logging-while-drilling thermal-neutron and gamma-ray time decays,” Geophysics, vol. 80, no. 3, pp. D247-D263, 2015.
E. Ortega, Torres-Verdín, C., and Preeg, W. E., “2D inversion-based interpretation of logging-while-drilling thermal-neutron and gamma-ray time decays,” Geophysics, vol. 80, no. 3, 2015. Publisher's Version
D. DiCarlo, Huh, C., and Johnston, K. P., “Area 2: Use Of Engineered Nanoparticle-Stabilized CO2 Foams To Improve Volumetric Sweep Of CO2 EOR Processes,” National Energy Technology Laboratory (NETL), 2015. Publisher's VersionAbstract
The goal of this project was to develop a new CO2 injection enhanced oil recovery (CO2- EOR) process using engineered nanoparticles with optimized surface coatings that has better volumetric sweep efficiency and a wider application range than conventional CO2-EOR processes. The main objectives of this project were to (1) identify the characteristics of the optimal nanoparticles that generate extremely stable CO2 foams in situ in reservoir regions without oil; (2) develop a novel method of mobility control using “self-guiding” foams with smart nanoparticles; and (3) extend the applicability of the new method to reservoirs having a wide range of salinity, temperatures, and heterogeneity. Concurrent with our experimental effort to understand the foam generation and transport processes and foam-induced mobility reduction, we also developed mathematical models to explain the underlying processes and mechanisms that govern the fate of nanoparticle-stabilized CO2 foams in porous media and applied these models to (1) simulate the results of foam generation and transport experiments conducted in beadpack and sandstone core systems, (2) analyze CO2 injection data received from a field operator, and (3) aid with the design of a foam injection pilot test. Our simulator is applicable to near-injection well field-scale foam injection problems and accounts for the effects due to layered heterogeneity in permeability field, foam stabilizing agents effects, oil presence, and shear-thinning on the generation and transport of nanoparticle-stabilized C/W foams. This report presents the details of our experimental and numerical modeling work and outlines the highlights of our findings
M. Nole, Daigle, H., Mohanty, K. K., Hillman, J. I. T., and Cook, A., “Assessing Methane Migration Mechanisms at Walker Ridge, Gulf of Mexico, via 3D Methane Hydrate Reservoir Modeling,” AGU Fall Meeting Abstracts. 2015.
K. Sokolov, Stover, R., Joshi, P., Yoon, S. J., Murthy, A., Emelianov, S., and Johnston, K., “Biodegradable Plasmonic Nanoparticles: Overcoming Clinical Translation Barriers,” Optical Molecular Probes, Imaging and Drug Delivery. Optical Society of America, pp. OM3D. 4, 2015. Publisher's VersionAbstract
We present biodegradable gold nanoparticles with plasmon resonances in the NIR region that can provide a crucial link between the enormous potential of metal nanoparticles for cancer imaging and therapy and translation into clinical practice.
C. Jiang, Bryant, S., and Daigle, H., “A bundle of short conduits model of the pore structure of gas shale”. Unconventional Resources Technology Conference (URTEC), 2015.
H. Jiang, Daigle, H., and Hayman, N. W., “Characterization of Connectivity between Fractures and Nano-pores in Shale Using Gas Adsorption Analysis,” AGU Fall Meeting Abstracts. 2015.
Y. Chen, Elhag, A. S., Cui, L., Worthen, A. J., Reddy, P. P., Noguera, J. A., Ou, A. M., Ma, K., Puerto, M., and Hirasaki, G. J., “CO2-in-water foam at elevated temperature and salinity stabilized with a nonionic surfactant with a high degree of ethoxylation,” Industrial & Engineering Chemistry Research, vol. 54, no. 16, pp. 4252-4263, 2015. Publisher's VersionAbstract
The utilization of nonionic surfactants for stabilization of CO2 foams has been limited by low aqueous solubilities at elevated temperatures and salinities. In this work, a nonionic surfactant C12–14(EO)22 with a high degree of ethoxylation resulted in a high cloud point temperature of 83 °C even in 90 g/L NaCl brine. Despite the relatively high hydrophilic–CO2-philic balance, the surfactant adsorption at the C–W interface lowered the interfacial tension to ∼7 mN/m at a CO2density of ∼0.85 g/mL, as determined with captive bubble tensiometry. The adsorption was sufficient to stabilize a CO2-in-water (C/W) foam with an apparent viscosity of ∼7 cP at 80 °C, essentially up to the cloud point temperature, in the presence of 90 g/L NaCl brine in a 30 darcy sand pack. In a 1.2 darcy glass bead pack, the apparent viscosity of the foam in the presence of 0.8% total dissolved solids (TDS) brine reached the highest viscosity of ∼350 cP at 60% foam quality (volume percent CO2) at a low superficial velocity of 6 ft/day. Shear-thinning behavior was observed in both the glass bead pack and the sand pack irrespective of the permeability difference. In addition, C12–14(EO)22 stabilized C/W foam with an apparent viscosity of 80–100 cP in a 49 mdarcy dolomite core formed through a coinjection and a surfactant-alternating-gas process. The dodecane–0.8% TDS brine partition coefficient for C12–14(EO)22 was below 0.1 at 40 °C and 1 atm. The formation of strong foam in the porous media and the low oil–brine partition coefficient indicate C12–14(EO)22 has potential for CO2-enhanced oil recovery.
Z. Xue, Panthi, K., Fei, Y., Johnston, K. P., and Mohanty, K. K., “CO2-Soluble Ionic Surfactants and CO2 Foams for High-Temperature and High-Salinity Sandstone Reservoirs,” Energy & Fuels, vol. 29, no. 9, pp. 5750-5760, 2015. Publisher's VersionAbstract
The sweep efficiency of CO2 enhanced oil recovery can be improved by forming viscous CO2-in-water (C/W) foams that increase the viscosity of CO2. The goal of this study is to identify CO2-soluble ionic surfactants that stabilize C/W foams at elevated temperatures up to 120 °C in the presence of a high salinity brine using aqueous phase stability, static and dynamic adsorption, CO2 solubility, interfacial tension, foam bubble size, and foam viscosity measurements. An anionic sulfonate surfactant and an amphoteric acetate surfactant were selected to achieve good thermal and chemical stability, and to minimize adsorption to sandstone reservoirs in the harsh high-salinity high-temperature brine. The strong solvation of the surfactant head by the brine phase and surfactant tail by CO2 allows efficient reduction of the C/W interfacial tension, and the formation of viscous C/W foams at high salinity and high temperature. Furthermore, the effect of temperature and methane dilution of CO2 on foam viscosity was evaluated systematically in both bulk and porous media. High temperature reduces the stability of foam lamella, which leads to lower lamella density and, therefore, lower foam viscosity. Methane dilution of CO2 reduces the solvation of surfactant tails and makes the surfactant less CO2-philic at the interface. The consequent increase of the interfacial tension decreases the stability of foam lamella, as seen by the increase in foam bubble size, thereby reducing foam viscosity.
S. Misra, Torres-Verdín, C., Homan, D., and Rasmus, J., “Complex electrical conductivity of mudrocks and source-rock formations containing disseminated pyrite (Expanded Abstract),” Unconventional Resources Technology Conference (URTeC). San Antonio, Texas, July 20 – 22, 2015.
S. Misra, Torres-Verdín, C., Homan, D., and Rasmus, J., “Complex electrical conductivity of mudrocks and source-rock formations containing disseminated pyrite (Expanded Abstract),” Unconventional Resources Technology Conference (URTeC). San Antonio, Texas, July 20 – 22, 2015.
A. W. Sanders, Johnston, K. P., Nguyen, Q., Adkins, S., Chen, X., and Rightor, E. G., “Compositions for oil recovery and methods of their use”. US Patent 8,973,668, 2015. Publisher's VersionAbstract
Embodiments of the present disclosure include compositions for use in enhanced oil recovery, and methods of using the compositions for recovering oil. Compositions of the present disclosure include a nonionic, non-emulsifying surfactant having a CO2-philicity in a range of about 1.5 to about 5.0, carbon dioxide in a liquid phase or supercritical phase, and water, where the nonionic, non-emulsifying surfactant promotes a formation of a stable foam formed of carbon dioxide and water
I. Kholmanov, Kim, J., Ou, E., Ruoff, R. S., and Shi, L., “Continuous Carbon Nanotube–Ultrathin Graphite Hybrid Foams for Increased Thermal Conductivity and Suppressed Subcooling in Composite Phase Change Materials,” ACS Nano, vol. 9, pp. 11699-11707, 2015. Publisher's Version
B. Vigaru, Sulzer, J., and Gassert, R., “Design and Evaluation of a Cable-Driven fMRI-Compatible Haptic Interface to Investigate Precision Grip Control,” Haptics, IEEE Transactions on, no. 99, pp. 1-13, 2015.
D. N. Espinoza, Pereira, J. - M., Vandamme, M., Dangla, P., and Vidal-Gilbert, S., “Desorption-induced shear failure of coal bed seams during gas depletion,” International Journal of Coal Geology, vol. 137, pp. 142-151, 2015. Publisher's Version
K. Yang, Torres-Verdín, C., and Yilmaz, A. E., “Detection and quantification of three-dimensional hydraulic fractures with horizontal borehole resistivity measurements,” IEEE Transactions on Geoscience and Remote Sensing (TGRS), v. 53, no. 8, pp. 4605–4615. , vol. 53, no. 8, pp. 4605–4615, 2015.
K. Yang, Torres-Verdín, C., and Yilmaz, A. E., “Detection and quantification of three-dimensional hydraulic fractures with horizontal borehole resistivity measurements,” IEEE Transactions on Geoscience and Remote Sensing (TGRS), vol. 53, no. 8, pp. 4605–4615, 2015.
C. Huh, Bryant, S. L., Milner, T. E., and Johnston, K. P., “Determination of oil saturation in reservoir rock using paramagnetic nanoparticles and magnetic field”. US Patent 9,133,709, 2015. Publisher's VersionAbstract
Methods for detection of the presence and distribution of oil in subsurface formation are described herein. The present invention involves injection of an aqueous dispersion of the nanoparticles into the potentially oil containing subsurface formation, followed by a remote detection of the oscillation responses of the nanoparticles in the oil/water interfaces in the reservoir rock by applying magnetic field.
C. Huh, Bryant, S. L., Milner, T. E., and Johnston, K. P., “Determination of oil saturation in reservoir rock using paramagnetic nanoparticles and magnetic field”. US Patent App. 14/853,519, 2015. Publisher's VersionAbstract
Methods for detection of the presence and distribution of oil in subsurface formation are described herein. The present invention involves injection of an aqueous dispersion of the nanoparticles into the potentially oil containing subsurface formation, followed by a remote detection of the oscillation responses of the nanoparticles in the oil/water interfaces in the reservoir rock by applying magnetic field.
H. Daigle, Ezidiegwu, S., and Turner, R., “Determining Relative Permeability In Shales By Including The Effects Of Pore Structure On Unsaturated Diffusion And Advection,” SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2015.

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