Whole cells and cell-wall fractions of Staphylococcusaureus have been labeled by various combinations of [1-13C]glycine, [15N]glycine, L--6-13C-lysine, L--6-15N-lysine, D--1-13C-alanine, and D--15N-alanine. The resulting materials have been examined using 13C and 15N solid-state, magic-angle spinning NMR techniques including cross-polarization, double cross-polarization, and rotational-echo double resonance. The results of these measurements indicate that the peptidoglycan glycyl bridges are complete (five units long) and form cross-links between three-quarters of all peptide stems. The pentaglycyl bridges are immobilized in lyophilized cell-wall fractions in a compact conformation with inter-residue spacings comparable to those of an alpha helix. The bridges have a similar compact conformation in intact whole cells, regardless of whether the cells have been lyophilized or were hydrated and frozen at -10 degrees C. The bridges are also in a time-averaged compact conformation in whole cells at 0 degrees C but with sizable structural fluctuations associated with local mobility. A small fraction of bridges are in extended-chain conformations.

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The pore structure of shale gas reservoirs has strong heterogeneity, and the flow mechanism in multiscale media is complex. The fracture network of hydraulic fracturing is significantly affected by reservoir in situ stress, rock mechanical properties, and natural fracture distribution. At present, there is no efficient and accurate inversion method for fracture networks. Accurately describing fracture network morphology and flow capacity distribution of induced fracture is an important basis for production analysis, fracturing evaluation, and production plan. This article focuses on the hot issues of shale gas development, from three aspects: flow parameter characterization method of organic/inorganic matter, multiscale mass transfer simulation of shale gas reservoir, and inversion method of fracture network morphology and flow capacity, to introduce relevant research progress in detail. At the same time, the advantages and shortcomings of current related researches are compared and analyzed. Based on this, the key scientific problems existing on flow mechanisms and inversion method of fracture network in shale gas reservoirs are proposed, which can provide guidance for further research.

Influenced by the complex sedimentary environment, a well always penetrates multiple layers with different properties, which leads to the difficulty of analyzing the production behavior for each layer. Therefore, in this paper, a semi-analytical model to evaluate the production performance of each layer in a stress-sensitive multilayer carbonated gas reservoir is proposed. The flow of fluids in layers composed of matrix, fractures, and vugs can be described by triple-porosity/single permeability model, and the other layers could be characterized by single porosity media. The stress-sensitive exponents for different layers are determined by laboratory experiments and curve fitting, which are considered in pseudo-pressure and pseudo-time factor. Laplace transformation, Duhamel convolution, Stehfest inversion algorithm are used to solve the proposed model. Through the comparison with the classical solution, and the matching with real bottom-hole pressure data, the accuracy of the presented model is verified. A synthetic case which has two layers, where the first one is tight and the second one is full of fractures and vugs, is utilized to study the effects of stress-sensitive exponents, skin factors, formation radius and permeability for these two layers on production performance. The results demonstrate that the initial well production is mainly derived from high permeable layer, which causes that with the rise of formation permeability and radius, and the decrease of stress-sensitive exponents and skin factors, in the early stage, the bottom-hole pressure and the second layer production rate will increase. While the first layer contributes a lot to the total production in the later period, the well bottom-hole pressure is more influenced by the variation of formation and well condition parameters at the later stage. Compared with the second layer, the scales of formation permeability and skin factor for first layer have significant impacts on production behaviors.

Blends of one part of carbonyl-13 C, ring-13 C, or methyl-13 C-labeled polycarbonate with nine parts of poly(p-fluorostyrene) or poly(o-fluorostyrene) have been examined by 13C−19F rotational-echo double-resonance NMR. The immiscible blends were formed by precipitation from choloroform solution into methanol. After being annealed at 180 °C, the blends consist of domains of polycarbonate (average diameter of 36 nm) dispersed in a matrix of polyfluorostyrene. There are no kinetically trapped polycarbonate chains. The interface is tightly packed, with an average polycarbonate−polyfluorostyrene nearest-neighbor separation of labels of less than 4 Å. The interface is also partially ordered, with the 19F distances to the polycarbonate isopropylidene moiety greater than to the carbonate group. Despite the tight packing at the interface, polycarbonate ring dynamics in chains nearest to polyfluorostyrene are indistinguishable from those in bulk polycarbonate.