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The natural gas can improve the flooding effect as its excellent flow property and dissolution ability, but it is also easily to form the serious gas channelling when injecting gas continuously. In...

The flowback behavior of hydraulic fractured horizontal well in shale gas reservoir is relatively different from that of conventional reservoirs. Therefore, it is necessary to investigate the relationship between the potential influencing factors and the flowback behavior in shale gas reservoirs. This study is based on experimental observations and numerical simulations. In the experiments, the flowback process was simulated through a gas displacement experiment, and the cores were scanned simultaneously to obtain the water distribution. Then, the water migration and retention mechanisms were investigated to determine the flowback behavior. For the numerical simulations, a multi-porosity model was established. The mathematical model accounted for the capillary pressure term. By matching the fluid saturation-front curves of the experimental and simulation results, a fitted capillary pressure curve, which reflects the multiple mechanisms controlling flowback, was obtained. Based on the established model and fitted capillary pressure, the flowback behavior and relevant influencing factors of the shale gas were investigated. The results show that the flowback ratio is inversely proportional to the clay content of the shale. A high salinity fracturing fluid or a surfactant solution can increase the flowback ratio. In addition, the injection pressure is proportional to the flowback ratio, while the matrix permeability and the flowback ratio have an inverse relationship. The adsorption–desorption process of gas has no significant effect on the flowback ratio. This study aims to provide a new method for analyzing the flowback performance of shale gas using a combination of experimental and numerical simulation methods.

Shale gas development requires large-scale hydraulic fracturing, but a large amount of the slickwater fracturing fluid injected into the reservoir cannot be brought back to the surface. In this study, spontaneous imbibition and reverse displacement experiments were carried out on shale core to simulate fracturing fluid imbibition into the matrix during the fracturing stage of a shale gas reservoir and the displacement of fracturing fluid by reservoir gas during the flowback stage. With the help of low-field nuclear magnetic resonance technology to dynamically monitor the volume change in the liquid in the shale core throughout the entire process, the volume distribution of the liquid in the pores of the different scales were calculated at each time. The reason for the low flowback efficiency of shale gas reservoirs from the perspective of pore size was studied, and the influence of the fracturing fluid’s salinity on the flowback process was analyzed. The research results show that there is a certain pore size threshold in the shale gas reservoir. When the fracturing fluid enters pores smaller than this size threshold, it is difficult to displace it during flowback. The relative volume of the fracturing fluid entering the pores smaller than the size threshold determines the flowback efficiency. The higher the proportion of this part of the fracturing fluid to the total volume, the lower the flowback efficiency. Using a fracturing fluid with a higher salinity can reduce the volume of liquid entering the pores less than the pore threshold to a certain extent, thereby increasing the flowback efficiency. This research is important for gaining a better understanding the low flowback efficiency in shale gas reservoirs and for evaluating the safety of groundwater resources.

Due to well-developed natural fractures, tight oil reservoirs always described as stress sensitive dual media reservoir. So far, the pressure distribution model for multi-stage fractured horizontal well (MFW) in stress sensitive reservoir is almost solved by numerical method. This paper gives the semi-analytical solution to this problem. Firstly, with consideration of stress sensitivity, a transient pressure behavior model of MFW was established. Using perturbation transform, Laplace transform, image theory and superposition principle the mathematical model was solved. Finally, by applying stehfest numerical inversion and perturbation inverse transform, we get the transient pressure for MFW in the time domain. According to the result of calculation, the flow process of MFW can be identified as six regimes: Ⅰ linear flow, Ⅱ the first radial flow, Ⅲ double radial flow, Ⅳ radial flow in the natural fractures system, Ⅴ cross flow, Ⅵ radial flow in the entire reservoir. Stress-sensibility primarily influences the latter five stages. The well bore dimensionless pressure drop is several times larger comparing with the situation that don't take the stress sensitive into account, and the dimensionless pressure drop derivative curve will tilte up in the later flow process, showing the characteristic of closed boundary. Accordingly, the calculating error will be larger and can mislead the interpretation of well testing.

Spontaneous imbibition is the main mechanism responsible for the retention of large amounts of fracturing fluid during the flowback period in shale gas development. Studying the mechanism of imbibition will help optimize flowback design and improve the accuracy of production prediction. Previous experiments have mainly focused on studying the relationship between the amount of liquid imbibed into shale samples and the time. However, these experiments could not describe visually the liquid saturation distribution along rock samples. In this paper, a chemical potential-dominated flow mechanism model is presented, and nuclear magnetic resonance is adopted to obtain the water saturation distribution curve in the shale rock sample during spontaneous imbibition. The tight sandstone sample is also investigated for comparison. The effects of clay mineral content, fluid salt concentration, and surfactant solution on the water saturation distribution curve are systematically investigated. Results show that the adva...

High-clay shale formations could behave as a semi-permeable membrane, thus causing osmotic water molecules flow from low-salinity side to the high-salinity side. This chemical potential dominated flow, we believe, has non-negligible influence on water leak-off and flowback during the treatment of hydraulic fracturing, since there is a considerable salinity difference between the low-salinity fracturing-fluid and the high-salinity formation brine. In this paper, we present the development of a comprehensive triple-porosity (organic materials, inorganic materials and fracture network), dual-permeability, chemical potential dominated water/gas flow model that uses experimentally determined formation properties to predict the fracturing fluid flowback of hydraulically fractured shale gas wells. The dual-permeability includes the chemical potential dominated flow within inorganic materials and the pressure dominated flow within fracture network. Fracture network is considered as an interconnected continuum embedded in shale matrix, where organic shale is interspersed within vast inorganic shale. The organic material is thus considered disconnected in the entire reservoir. The chemical potential dominated flow model accounts chemical osmosis, capillary and viscous forces. The water saturation profiles for both osmosis-induced and capillary-induced cases are compared, revealing a region of saturation that effectively is immobile even though irreducible saturation has not been reached. The results indicate that chemical osmosis is a key mechanism for fluid loss during the hydraulic fracturing and should not be ignored under high clay content cases. This work provides a basis for flowback data analysis of hydraulically fractured shale gas wells and also helps define value adding laboratory measurements.

The syntheses of a series of CpW(CO)2(π-γ-lactonyl) complexes bearing a tethered aldehyde are described. These π-allyl complexes are prepared as either syn- or anti-stereoisomers. Treatment of these dicarbonyl complexes with NOBF4 and NaI in CH3CN effects an intramolecular allylation of the tethered aldehyde, yielding bicyclic α-methylene butyrolactones comprising a homoallylic alcohol. Both syn- and anti-isomers of tungsten-π-allyl compounds produce the same α-methylene butyrolactones. The cyclizations proceed with high diastereoselectivities to give only the cis-fused bicyclic γ-lactones. The preference for cis-fused stereoselection can be rationalized based on a tricyclic transition state mechanism.

The characteristic pathogenic autoantibodies in Goodpasture's syndrome (GPS) are directed to the noncollagenous domain (NC1) of basement membrane type IV collagen. To examine whether immunization with anti-NC1 antibodies could lead to GPS-like pathology, naive BALB/c mice were immunized intradermally with a mouse IgG anti-NC1 monoclonal antibody or IgG serum fraction derived from patients with GPS. Mice immunized with normal mouse or human IgG and nonimmunized mice served as controls. Anti-NC1 antibodies of IgG isotype were detected in the sera of mice injected with anti-NC1 antibodies, but not in the sera of control mice. The presence of circulating anti-NC1 antibodies coincided in some of the mice erythrocyturia or proteinuria and pathological changes in the kidneys. No pathologic alterations were seen in the control mice. The results show that specific idiotypic manipulation can induce anti-NC1 antibodies and pathological changes resembling human GPS.