The macromolecular pigment-protein complex has the merit of high efficiency for light-energy capture and transfer after long-term photosynthetic evolution. Here bio-dyes of A. platensis photosystem I (PSI) and spinach light-harvesting complex II (LHCII) are spontaneously sensitized on three types of designed TiO2 films, to assess the effects of pigment-protein complex on the performance of bio-dye sensitized solar cells (SSC). Adsorption models of bio-dyes are proposed based on the 3D structures of PSI and LHCII, and the size of particles and inner pores in the TiO2 film. PSI shows its merit of high efficiency for captured energy transfer, charge separation and transfer in the electron transfer chain (ETC), and electron injection from FB to the TiO2 conducting band. After optimization, the best short current (JSC) and photoelectric conversion efficiency (η) of PSI-SSC and LHCII-SSC are 1.31 mA cm-2 and 0.47%, and 1.51 mA cm-2 and 0.52%, respectively. The potential for further improvement of this PSI based SSC is significant and could lead to better utilization of solar energy.

Droplet dynamics on a solid substrate is significantly influenced by surfactants. It remains a challenging task to model and simulate the moving contact line dynamics with soluble surfactants. In this work, we present a derivation of the phase-field moving contact line model with soluble surfactants through the first law of thermodynamics, associated thermodynamic relations and the Onsager variational principle. The derived thermodynamically consistent model consists of two Cahn–Hilliard type of equations governing the evolution of interface and surfactant concentration, the incompressible Navier–Stokes equations and the generalized Navier boundary condition for the moving contact line. With chemical potentials derived from the free energy functional, we analytically obtain certain equilibrium properties of surfactant adsorption, including equilibrium profiles for phase-field variables, the Langmuir isotherm and the equilibrium equation of state. A classical droplet spread case is used to numerically validate the moving contact line model and equilibrium properties of surfactant adsorption. The influence of surfactants on the contact line dynamics observed in our simulations is consistent with the results obtained using sharp interface models. Using the proposed model, we investigate the droplet dynamics with soluble surfactants on a chemically patterned surface. It is observed that droplets will form three typical flow states as a result of different surfactant bulk concentrations and defect strengths, specifically the coalescence mode, the non-coalescence mode and the detachment mode. In addition, a phase diagram for the three flow states is presented. Finally, we study the unbalanced Young stress acting on triple-phase contact points. The unbalanced Young stress could be a driving or resistance force, which is determined by the critical defect strength.

No abstract

Shale gas reservoirs have received considerable attention for their potential in satisfying future energy demands. Technical advances in horizontal well drilling and hydraulic fracturing have paved the way for the development of shale gas reservoirs. Compared with conventional gas reservoir, adsorbed gas accounts for a large proportion of total gas within shale, so the amount of gas desorbed from the formation has a large impact on the ultimate gas recovery. Recently, efforts toward the thermal recovery of shale oil based on hydraulic fracture heating technology (ExxonMobil's Electrofrac) have made some progress. However, the temperature-dependent adsorption behavior and its major applications of evaluating thermal stimulation as a recovery method have not been thoroughly explored. Additionally, many complicated nonlinear processes coexist in shale formation such as Knudsen diffusion, the pressure dependent phenomenon and non-Darcy flow, presenting a significant challenge for quantifying flow in shale gas reservoir.To investigate the effect of thermal recovery based on hydraulic fracture heating, a fully coupled numerical model of a fractured horizontal well is developed to capture the real gas flow in shale gas reservoir. Discrete fracture, dual continuum media and single porosity media are employed to describe the hydraulic fractures, the stimulated reservoir volume (SRV) region and the matrix, respectively. The model incorporates non-linear flow mechanisms including adsorption/desorption, Knudsen diffusion, non-Darcy flow and pressure dependent phenomenon, as well as heat diffusion processes within the shale reserve. Then, the effectiveness of formation factors on thermal recovery is analyzed.The results show that hydraulic fracture heating can actually enhance shale gas recovery by altering gas desorption behavior, and that this method is more suitable for long-term production. More adsorbed gas can be recovered with increasing simulation temperature. The thermal properties of the shale formation only have limited impacts on the long-term production. The gas production rate is primarily determined by the simulation temperature, matrix adsorption ability, fracture spacing, area of the SRV region, bottom hole pressure (BHP) and reservoir permeability. A shale gas reservoir with a large Langmuir volume and SRV area, relatively small fracture spacing, and a high BHP has the potential for thermal treatment to enhance gas recovery. The fracture temperature, the area of the SRV region and the fracture spacing are the only three factors that can be controlled during the design and execution of thermal treatment in the field.

No abstract