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Purpose Our study was to investigate the correlation between 18F-FDG uptake in HCC and tumor PD-L1 expression in HCC, and assess the value of 18F-FDG PET/CT imaging for predicting PD-L1 expression in HCC. Methods A total of 102 patients with confirmed HCC were included in this retrospective study. The PD-L1 expression and immune cell infiltrating of tumors were determined through immunohistochemistry staining. The SUVmax of HCC lesions were assessed using 18F-FDG PET/CT. The correlation between PD-L1 expression and the clinicopathological were evaluated by the Cox proportional hazards model and the Kaplan-Meier survival analysis Results The SUVmax of HCC primary tumors was higher in patients with poorly differentiated HCC, large tumor size, portal vein tumor thrombus, lymph node and distant metastases, and death. The SUVmax of HCC are correlated with the PD-L1 expression and the number of cytotoxic T cells and M2 macrophage infiltration. PD-L1 expression was significantly correlated with tumor SUVmax, tumor differentiation, tumor size, portal vein tumor thrombosis, and patient survival status and infiltrating M2 macrophages. Further, our results confirmed that SUVmax, portal vein tumor thrombosis, and the number of infiltrating M2 macrophages were closely related to PD-L1 expression and were independent risk factors by multivariate analysis. The combined assessment of SUVmax values and the presence of portal vein tumor thrombosis by 18F-FDG PET/CT imaging can help determine PD-L1 expression in HCC. Conclusions FDG uptake in HCC was positively correlated with the PD-L1 expression and the number of cytotoxic T cells and M2 macrophage infiltration. The combined use of SUVmax and portal vein tumor thrombosis by PET/CT imaging assess the PD-L1 expression better in HCC. These findings also provide a basis for clinical studies to assess the immune status of tumors by PET/CT.

We prove that certain crystabelline deformation rings of two dimensional residual representations of $$\mathrm {Gal}(\overline{\mathbb {Q}}_p/\mathbb {Q}_p)$$ are Cohen–Macaulay. As a consequence, this allows to improve Kisin’s $$R[1/p]=\mathbb {T}[1/p]$$ theorem to an $$R=\mathbb {T}$$ theorem.

The aim of the study involves examining the effect of heavy oil viscosity on fracture geometry in detail by establishing a heavy oil fracturing model and conventional fracturing model based on thermal–hydraulic–mechanical (THM) coupled theory, Walther viscosity model, and K–D–R temperature model. We consider viscosity and density within the heavy oil fracturing model as functions of pressure and temperature while that as constants within the conventional fracturing model. A heavy oil production well is set as an example to analyze the differences between the two models to account for the thermo-poro-elastic effect. The results show that temperature exhibits the most significant influence on the heavy oil viscosity while the influence of pressure is the least. In addition, a cooling area with a width of 0–1 m and varied length is generated near the fracture. The heavy oil viscosity increases sharply in this area, thereby indicating an area of viscosity increment. The heavy oil viscosity increases faster and is closer to wellbore, and a high viscosity increment reduces the mobility of the heavy oil and prevents the fracturing fluid from entering into the reservoir. The special viscosity distribution results in significant differences in pore pressure, oil saturation, and changing trends between these two models. In the heavy oil reservoir fracturing model, the thermal effect completely exceeds the influence of pore elasticity, and the values of the fracture length, width, and static pressure exceed those calculated in the conventional fracturing model. Thus, a comparison of the measured values indicates that the results obtained by considering viscosity as a function of temperature and pressure are more accurate. Therefore, the results of this study are expected to provide good guidelines for the design of heavy oil fracturing.

Based on the impact of the stress perturbation effect created by simultaneous propagation of multiple fractures in the process of simultaneous hydraulic fracturing, a thorough research on the mechanism and adaptation of simultaneous fracturing of double horizontal wells in ultra-low permeability sandstone reservoirs was conducted by taking two adjacent horizontal wells (well Yangping-1 and well Yangping-2 located in Longdong area of China Changqing Oilfield) as field test wells. And simultaneous fracturing optimal design of two adjacent horizontal wells was finished and employed in field test. Micro-seismic monitoring analysis of fracture propagation during the stimulation treatment shows that hydraulic fractures present a pattern of complicated network expansion, and the well test data after fracturing show that the daily production of well Yangping-1 and well Yangping-2 reach 105.8 t/d and 87.6 t/d, which are approximately 9.4 times and 7.8 times the daily production of a fractured vertical well in the same area, respectively. Field test reflects that simultaneous hydraulic fracturing of two adjacent horizontal wells can enlarge the expansion area of hydraulic fractures to obtain a lager drainage area and realize the full stimulation of ultra-low permeability sandstone reservoirs in China Changqing oilfield. Therefore, simultaneous fracturing of two adjacent horizontal wells provides a good opportunity in stimulation techniques for the efficient development of ultra-low permeability reservoirs in China Changqing oilfield, and it has great popularization value and can provide a new avenue for the application of stimulation techniques in ultra-low permeability reservoirs in China.

The ultra-low-permeability shale gas reservoir has a lot of well-developed natural fractures. It has been proven that hydraulic fracture growth pattern is usually a complex network fracture rather than conventional single planar fractures by micro-seismic monitoring, which can be explained as the shear and tensile failure of natural fractures or creation of new cracks due to the increase in reservoir pore pressure caused by fluid injection during the process of hydraulic fracturing. In order to simulate the network fracture growth, a mathematical model was established based on full tensor permeability, continuum method and fluid mass conservation equation. Firstly, the governing equation of fluid diffusivity based on permeability tensor was solved to obtain the reservoir pressure distribution. Then Mohr–Coulomb shear failure criterion and tensile failure criterion were used to decide whether the rock failed or not in any block on the basis of the calculated reservoir pressure. The grid-block permeability was modified according to the change of fracture aperture once any type of rock failure criterion was met within a grid block. Finally, the stimulated reservoir volume (SRV) zone was represented by an enhancement permeability zone. After calibrating the numerical solution of the model with the field micro-seismic information, a sensitivity study was performed to analyze the effects of some factors including initial reservoir pressure, injection fluid volume, natural fracture azimuth angle and horizontal stress difference on the SRV (shape, size, bandwidth and length). The results show that the SRV size increases with the increasing initial pore reservoir and injection fluid volume, but decreases with the increase in the horizontal principal stress difference and natural fracture azimuth angle. The SRV shape is always similar for different initial pore reservoir and injection fluid volume. The SRV is observed to become shorter in length and wider in bandwidth with the decrease in natural fracture azimuth angle and horizontal principal stress difference.