Search

Natural fractures within the lacustrine mixed shale oil reservoirs of the upper member of the Lower Ganchaigou Formation (E32) in the Ganchaigou area of the Qaidam Basin are pivotal to the exploration and development of shale oil and gas. This research investigates the developmental characteristics and controlling factors of natural fractures and their impact on the reservoir quality based on cores, image logs, thin sections, scanning electron microscopy observations, and experimental and production data. The results indicate that natural fractures in the E32 are categorized into tectonic fractures, diagenetic fractures, and abnormal high-pressure fractures. Tectonic fractures are characterized by a significant variation in dip angles, a wide range of apertures, low density, and a high filling degree. Diagenetic fractures typically exhibit low dip angles, small apertures, high density, and a low filling degree. Abnormal high-pressure fractures display chaotic orientations and complex styles, often consisting of filled fractures. The development and distribution of natural fractures are jointly influenced by mineral composition and brittleness, lamination structure, organic matter content and maturity, diagenesis, tectonic factors, and abnormal high pressure. A high content of dolomite, thin-bedded structures comprising carbonate laminae and felsic laminae, and abundant mature organic matter provide a favorable foundation for fracture development. Diagenesis, including dissolution, pressure solution, and mineral dehydration shrinkage, acts as a beneficial guarantee for fracture development. Tectonic locations near the hanging wall of faults and the core of anticlines are the main regions for fracture development. Abnormal high pressure is a crucial driving force for fracture development. Interconnected natural fractures of various types and scales significantly expand reservoir space and enhance pore connectivity and flow capacity, serving a vital function in maintaining high and stable production in lacustrine mixed shale oil reservoirs.

The Weixinan Sag in the Beibuwan Basin is rich in shale oil resources. However, the reservoirs exhibit rapid phase changes, strong compartmentalization, thin individual layers, and high-frequency vertical variations in the thin interbedded sandstone and mudstone. These factors can restrict the height of hydraulic fracture propagation. Additionally, the low-porosity and low-permeability shale oil reservoirs face challenges such as low production rates and rapid decline. To address these issues, the Plannar3D full 3D fracturing model was used to simulate hydraulic fracture propagation and to study the main controlling factors for fracture propagation in the second member of the Liushagang Formation. Based on the concept of geological–engineering integration, a sweet spot evaluation was conducted to identify reservoirs with relatively better brittleness, reservoir properties, and oil content as the fracturing targets for horizontal wells. The UFM model was then applied to optimize fracturing parameters. This study indicates that the matrix-type oil shale has a high clay mineral content, resulting in a low Young’s modulus and poor brittleness. This makes hydraulic fracture propagation difficult and leads to less effective reservoir stimulation. In contrast, hydraulic fractures propagate more easily in high-brittleness interlayer-type oil shale. Therefore, it is recommended to prioritize the extraction of shale oil from interlayer-type oil shale reservoirs. The difference in interlayer stress is identified as the primary controlling factor for cross-layer fracture propagation in the study area. Based on the concept of geological–engineering integration, a sweet spot evaluation standard was established for the second member of the Liushagang Formation, considering both reservoir quality and engineering quality. Four sweet spot zones of interlayer-type oil shale reservoirs were identified according to this evaluation standard. To achieve uniform fracture initiation, a differentiated segment and cluster design was implemented for certain high-angle sections of well WZ11-6-5d. Interlayer-type oil shale was selected as the fracturing target, and the UFM was used for hydraulic fracture propagation simulation. Fracturing parameters were optimized with a focus on hydraulic fracture characteristics and the estimated ultimate recovery (EUR). The optimization results were as follows: a single-stage length of 50 m, cluster spacing of 15 m, pump injection rate of 10 m3/min, fluid intensity of 25 m3/m, and proppant intensity of 3.5 t/m. The application of these optimized fracturing parameters in field operations resulted in successful fracturing and the achievement of industrial oil flow.

Platform well fracturing is essential for the efficient development of unconventional oil and gas (UOG), and it has been widely applied in oilfields. Field practices have revealed that various fracturing methods result in different stimulation performances, but the mechanisms responsible for these differences are not completely understood. To explore the characteristics of the inter-well stress interference of various platform well fracturing methods, a numerical model was established for the systematic assessment of the stress field of simultaneous fracturing, zipper fracturing (ZF), modified zipper fracturing, and synergic fracturing (SF). Based on these analyses, balanced stress fracturing (BSF) has been proposed to significantly reduce the horizontal stress difference. This study indicates that the fracturing methods significantly impact the evolution of induced stress, and that ZF and SF can achieve a balanced stress field and the utilization of an inter-well reservoir through a reasonable fracture distribution mode and fracturing operation. Combined with the interlaced fracture distribution mode, interactive fracturing, and overall front parallel fracturing, BSF can improve the fracture network complexity (FNC) and reduce the risk of casing deformation. Moreover, BSF helps achieve higher production and a more uniform stress field in platform well fracturing. This study presents an effective measure to increase FNC and reduce the occurrence of casing deformation during UOG development.

Background Hepatocellular carcinoma (HCC) is a malignancy with limited treatment options and poor prognosis. Macrophages are enriched in the HCC microenvironment and have a significant impact on disease progression and therapy efficacy. We aim to identify critical macrophages subsets involved in HCC development.Methods Macrophage-specific marker genes were identified through single-cell RNA sequencing analyses. The clinical significance of macrophages with palmitoyl-protein thioesterase 1 (PPT1) positive was investigated in 169 patients with HCC from Zhongshan Hospital using immunohistochemistry and immunofluorescence. The immune microenvironment of HCC and the functional phenotype of PPT1+ macrophages were explored using cytometry by time-of-flight (CyTOF) and RNA sequencing.Results Single-cell RNA sequencing analyses revealed that PPT1 was predominantly expressed in macrophages in HCC. Intratumoral PPT1+ macrophages abundance was associated with inferior survival durations of patients and an independent risk factor of prognosis for HCC. High throughput analyses of immune infiltrates showed that PPT1+ macrophage-enriched HCCs were characterized by high infiltration of CD8+ T cells with increased programmed death-1 (PD-1) expression. PPT1+ macrophages exhibited higher galectin-9, CD172a, and CCR2 levels but lower CD80 and CCR7 levels than PPT1− macrophages. Pharmacological inhibition of PPT1 by DC661 suppressed mitogen-activated protein kinase (MAPK) pathway activity but activated nuclear factor kappa B (NF-κB) pathway in macrophages. In addition, DC661 enhanced the therapeutic efficacy of anti-PD-1 antibody in the HCC mouse model.Conclusions PPT1 is mainly expressed in macrophages in HCC and promotes immunosuppressive transformation of macrophages and tumor microenvironment. PPT1+ macrophage infiltration is associated with poor prognosis of patients with HCC. Targeting PPT1 may potentiate the efficacy of immunotherapy for HCC.

Abstract Background Tumor-associated macrophages (TAMs), which form a large part of the tumor microenvironment, are normally regulated by metabolic reprogramming. However, the potential mechanisms of the immune-metabolism interaction between hepatocellular carcinoma (HCC) cells and TAMs remain unclear. Methods The candidate long non-coding RNAs (lncRNAs) were screened by Smart-seq based scRNA-seq method and then validated by qPCR. Immunostaining analysis was done to examine the levels of markers for TAMs and glycolysis. Exosomes from primary TAMs of human HCC tissues were isolated by centrifugation, and their internalization with lncRNAs was confirmed by immunofluorescence. The underlying mechanism of TAMs-derived exosomal lncRNA to HCC was confirmed by luciferase reporter assay and RNA immunoprecipitation. Metabolism regulation was evaluated through glucose consumption, lactate productions and extracellular acidification rates (ECARs). Mouse xenograft models were used to elucidate the in vivo effect of candidate lncRNAs on tumor growth. Results TAMs augment the aerobic glycolysis in HCC cells and their proliferation by the extracellular exosome transmission of a myeloid-derived lncRNA, M2 macrophage polarization associated lncRNA (lncMMPA). Mechanistically, lncMMPA not only could polarize M2 macrophage, but also could act as an microRNA sponge to interact with miR-548 s and increase the mRNA level of ALDH1A3, then further promote glucose metabolism and cell proliferation in HCC. Moreover, lncMMPA increased HCC cell multiplication through interacting with miR-548 s in vivo. Clinically, lncMMPA expression associates with glycolysis in TAMs and reduced survival of HCC patients. Conclusion LncMMPA plays an important role in regulating HCC malignancy and metabolic reprogramming of miR-548 s/ALDH1A3 pathway.

After the completion of multi-stage fracturing operation, the fluid pressure in artificial fracture network continues to decrease, resulting in the closure of fracture and the variation of local induced stress field. This process can also lead to the variation of fracture propagation pattern in the subsequent fracturing stages. To better guide fracturing design, the time effect of stress field was researched. A numerical method was used to solve the induced stress around a propped fracture, and analyze the influence of formation properties and treatment parameters on its change. Then, the characteristics of stress field with different closure times and its influence on subsequent fracture were investigated. Finally, the evolution of the stress field in two stimulated wells was analyzed using the instantaneous shut-in pressure. The results show that the original horizontal stress difference, fluid pressure in fracture, fracture length, fracture angle, and amount of proppant have significant effects on the variation of induced stress field. The stress field of formation with undeveloped natural fractures decreases quickly with the rapid closure of hydraulic fractures due to the rapid drop in fluid pressure, but the stress field remains relatively constant after the fracture is fully propped. For formation with developed low angle natural fractures, the stimulated stage promotes subsequent fracture propagation and improves fracturing efficiency. The fluid pressure declined slowly and is non-uniformly distributed during the closure of the complex fracture network. Therefore, the magnitude and scope of the induced stress vary unevenly with the closure time, and there is a reasonable treatment time to form complex fractures during hydraulic fracturing. This study provides new insights into fracturing operation.

Guanosine triphosphate binding protein 4 (GTPBP4) is a key regulator of cell cycle progression and MAPK activation. However, how its biological properties intersect with cellular metabolism in hepatocellular carcinoma (HCC) development remains poorly unexplained. Here, high GTPBP4 expression is found to be significantly associated with worse clinical outcomes in patients with HCC. Moreover, GTPBP4 upregulation is paralleled by DNA promoter hypomethylation and regulated by DNMT3A, a DNA methyltransferase. Additionally, both gain- and loss-of-function studies demonstrate that GTPBP4 promotes HCC growth and metastasis in vitro and in vivo. Mechanically, GTPBP4 can induce dimeric pyruvate kinase M2 (PKM2) formation through protein sumoylation modification to promote aerobic glycolysis in HCC. Notably, active GTPBP4 facilitates SUMO1 protein activation by UBA2, and acts as a linker bridging activated SUMO1 protein and PKM2 protein to induce PKM2 sumoylation. Furthermore, SUMO-modified PKM2 relocates from the cytoplasm to the nucleus may also could contribute to HCC progression through activating epithelial-mesenchymal transition (EMT) and STAT3 signaling pathway. Shikonin, a PKM2-specific inhibitor, can attenuate PKM2 dependent HCC glycolytic reprogramming, growth and metastasis promoted by GTPBP4, which offers a promising therapeutic candidate for HCC patients. Our findings indicate that GTPBP4-PKM2 regulatory axis plays a vital role in promoting HCC proliferation as well as metastasis by aerobic glycolysis and offer a promising therapeutic target for HCC patients.

Gravel is one of the main factors affecting the mechanical properties of conglomerates, which plays a decisive role in crack propagation. In this paper, taking the conglomerate of the Baikouquan Formation in Mahu Sag of Xinjiang as the research object, a three-dimensional model of the conglomerate is constructed by the discrete element numerical simulation method, and the triaxial compression experiment under different confining pressures is simulated. The mechanical properties and fracture morphology of conglomerate are analyzed with gravel content as a variable and verified by laboratory tests. In this simulation, with the increase of gravel content, the compressive strength of the conglomerate decreases, angle of internal friction decreases, and the fractures show different forms. The results show that the gravel morphology, spatial location, and gravel content have an impact on the mechanical properties of the conglomerate. The gravel content affects the formation process of the dominant fracture surface by controlling the distance between gravels so as to control the internal friction angle and it is the main controlling factor for the mechanical properties of the conglomerate. Gravel cracks initiate at the edge of gravel. Stress controls the formation of main cracks under low gravel content, and the influence of gravels under high gravel content makes cracks more discrete and complex.

To research the imbibition behavior of shale reservoirs, the imbibition experiments were conducted. However, clay-rich shale has small particle detachment during imbibition, which causes conventional imbibition method failure. A novel method was proposed to deal with this problem and the imbibition behavior of clay-rich shale was investigated. In conventional method, the apparent imbibed volume increases quickly at initial time and decreases sharply at late time because of particle detaching from sample. This phenomenon happened even though the samples were coated with epoxy resin, which indicated that the clay has strong swelling property. In novel method, both deionized water and different kinds of KCl solutions as well as epoxy resin were used. When deionized water was used, the apparent imbibed volume has a decreasing interval, which may be caused by bubble effect and osmotic effect. When both high KCl solution was used and sample was coated with epoxy resin, the decreasing interval disappeared. The ultimate apparent imbibed volume of higher KCl solution is lower than the lower KCl solution, which indicates that K+ restrains the clay swelling and reduces imbibed liquid. At last, the difference between apparent imbibed volume and corrected imbibed volume was discussed. The main contribution of this study is that a novel method was proposed for monitoring the imbibition behavior of clay-rich shale.

Abstract The frequent occurrence of casing failure has significantly affected the development of shale gas in the Sichuan Basin. Based on engineering and geology analyses, natural fracture/fault slip leads to casing shear deformation during hydraulic fracturing. Hence, natural fracture/fault slip and casing‐cement sheath‐formation assembly finite element models were established to quantitatively examine the characteristics of natural fracture/fault slip and mechanisms of casing shear deformation. Many factors, such as formation elastic property, in situ stress, natural fracture/fault geometry property, fluid pressure, casing elastic property, cement sheath elastic property, and well trajectory, were considered. The simulated results were in good agreement with the field data. The results indicated that natural fracture/fault slip leads to a sharp increase in casing deformation and stress in the adjacent region. Furthermore, factor sensitivity analysis results showed that a higher fluid pressure, larger fracture length, larger fracture dip angle, higher in situ stress difference, lower formation Young's modulus, and shorter distance from the wellbore to the center of the slip surface lead to severe casing stress and deformation. The countermeasures for preventing casing shear deformation involve decreasing the fracturing treatment pressure, reducing the crossing angle between the wellbore and natural fracture/fault, maintaining a safe distance from the wellbore to the large fracture/fault center, and adopting “balanced stress” fracturing operation. Hence, this study proposes a reasonable method to evaluate casing shear damage under hydraulic fracturing.

The conglomerate reservoir is rich in oil and gas reserves; however, the gravel's mechanical properties and laws are difficult to gain through laboratory experiments, which furthermore constrain the hydraulic fracturing design. To analyse the failure law of conglomerate, we simulated the uniaxial compression test based on discrete element software PFC2D and analysed the effect of different cementation strength, gravel content and gravel geometry on the rock deformation and failure characteristics. Results show that (i) as the cementation strength decreases, the compressive strength and elasticity modulus both reduce clearly, while the crack shapes get more complex and the critical value is 0.3; (ii) as the gravel content increases, the conglomerate strength first decreases then increases under the influences of cracks bypassing gravels; cementation strength and gravel content of the conglomerate both contribute to the increase in local additional stress, which leads to a series of changes in crack shapes and mechanical properties of the conglomerate. Based on the above research, the conglomerate strength and crack shapes after failure are relatively complex due to the common influence of cementation strength and gravel content. The gravel edge crack caused by stress concentration is the micro-mechanism that affects the conglomerate mechanical properties.

A large amount of fracturing fluid will be injected into the unconventional reservoirs during hydraulic fracturing. At present, the maximum amount of fracturing fluid injected into shale oil reaches 70000 m3 in Jimsar. The main function of fracturing fluid is to make fractures for traditional reconstruction of fracturing; for unconventional reservoirs, fracturing fluid is also used to increase formation energy by large-scale injection. It is of great significance to improve the utilization efficiency of large-scale hydraulic fracturing fluid for shale oil to increase production and recovery. In this study, the method of improving the utilization efficiency of the large-scale hydraulic fracturing fluids is explored by experiment, numerical simulation, and field test of Jimsar shale oil formation. This research shows that fracture complexity can effectively increase the contact area between the fracturing fluids and the formation. The water absorption rate of the fractured core is increased, which lays the foundation for improving the liquid utilization efficiency. Reasonably, well shutting before production ensures the pressure balance in the fractures, and the fluid pressure can be transmitted to the far end, which improves the fracture effectiveness, increases formation energy, and promotes imbibition and oil displacement. By using the additive of enhanced imbibition displacement, the displacement efficiency and the displacement amount of crude oil in the micro-nanopores can be greatly improved, and the utilization ratio of liquid can be further enhanced. The experiment adopted in the field proves that improving energy utilization efficiency has an important impact on production. This study has great guiding significance for the efficient development and practical production of unconventional reservoirs.

Hydraulic fracturing becomes an essential method to develop tight gas. Under high injection pressure, fracturing fluid entering into the formation will reduce the flow channel. To investigate the influence of water saturation on gas flow behavior, this study conducted the gas relative permeability with water saturation and the flow rate with the pressure gradient at different water saturations. As the two dominant tight gas-bearing intervals, the Upper Paleozoic Taiyuan and Shihezi Formations deposited in Ordos Basin were selected because they are the target layers for holding vast tight gas. Median pore radius in the Taiyuan Formation is higher than the one in the Shihezi Formation, while the most probable seepage pore radius in the Taiyuan Formation is lower than the one in the Shihezi Formation. The average irreducible water saturation is 54.4% in the Taiyuan Formation and 61.6% in the Shihezi Formation, which indicates that the Taiyuan Formation has more movable water. The average critical gas saturation is 80.4% and 69.9% in these two formations, respectively, which indicates that the Shihezi Formation has more movable gas. Both critical gas saturation and irreducible water saturation have a negative relationship with porosity as well as permeability. At the same water saturation, the threshold gradient pressure of the Taiyuan Formation is higher than the one in the Shihezi Formation, which means that water saturation has a great influence on the Taiyuan Formation. Overall, compared with the Shihezi Formation, the Taiyuan Formation has a higher median pore size and movable water saturation, but water saturation has more influence on its gas flow capacity. Our research is conducive to understanding the effect of fracturing fluid filtration on the production of natural gas from tight reservoirs.

Tight matrix has relatively low permeability and porosity, with abundant micro/nano pores. The capillary force in these pores are relatively strong, making the wetting liquid easier to be imbibed in the matrix. This process is called spontaneous imbibition. The complexity of pore structure is identified as one of the key factors influencing the imbibition process, but the detailed mechanism is not clear. Thus, in this work, a method is proposed to evaluate the influence of pore structure on imbibition process. Pore structure has fractal properties in a specific scale. By using the fractal theory, an imbibition model is provided to analyze the influence of microscopic structures on spontaneous imbibition, considering the pore size distribution and pore connectivity. Also, based on this model, the influencing factors on dimensionless imbibition and diffusion rate are discussed. Results show that the pore structure has more branches, larger and shorter sub-throats has higher chance to gain a high imbibition rate. Finally, a 3D imbibition parameter cube is constructed to determine the parameter combinations in favor of strong water diffusion potential. By utilizing the analysis method based on the fractal theory, we can effectively evaluate the imbibition potential. It is helpful to provide a guidance to evaluate the water imbibition to gas production.

Multistage hydraulic fracturing is a key technology for developing tight reservoirs. Field data indicate that a small fraction of the injected water can be recovered during flowback. Fractures play an important role in the retention of fracturing fluid, but the mechanisms and rules remain uncertain. Therefore, an experimental facility was established for studying the fluid retention in fractures using an improved conductivity apparatus. The fluid trapped in rough fractures was measured, and the dynamic changes of the drainage volume and rate under various apertures were analyzed. The effects of different factors, such as the fracture aperture, surface roughness, tortuosity, and matrix imbibition, on the fluid retention were studied. An empirical formula between the retention rate and fracture aperture was derived on the basis of mass conservation. Results showed that the fluid retention rate slowly decreased with an aperture increase in the fracture, and it would increase with considerable roughness, high tortuosity, and significant matrix imbibition. Meanwhile, drainage volume and rate change dramatically resulted from the gas drive. Secondary fractures and microcracks played an important role in the retention of fracturing fluid. Furthermore, the mechanisms of fracturing fluid retained in the tight reservoir, including viscous trapping and “locking” in fractures, the effect of gravity, surface-bound water film, capillary force retention, and matrix imbibition, were discussed. This study is significant for understanding the flowback rules of fracturing fluid, diagnosing fracture development, and identifying reservoir properties.

Tight sand gas is an important unconventional natural gas. Liquid filtration plays a main role in the formation damage. Flowback rate is closely related to the formation permeability recovery. Usually, the more flowback rate is, the better the permeability recovery is. In order to research the factors that influence the liquid flowback, the tight sand characteristics and gas displacement have been investigated. Some experiments were carried out, including porosity, permeability, XRD, casting thin section, SEM, stress sensitivity, rock expansion, and gas displacement. The results are shown as follows. Taiyuan formation has average high clay content than H8 formation. Illite is the main clay in Taiyuan formation; chlorite is the main clay in H8 formation. From the casting thin section, the rock has strong compression. Taiyuan formation has large pore. However, H8 formation mainly has small cracks. Through the SEM, there are many micro- to nanocracks as well as some pores in these two formations. In some cases, cracks penetrate the clays. From the permeability stress sensitivity, these tight sands have strong stress sensitivity. Permeability decreases quickly with increasing confining pressure. In the rock expansion experiment, the tight sand has less expansion rate compared with shale gas rock and volcanic gas rock. Rock expansion rate has positive relationship with clay content. In the gas displacement experiment, usually the higher the clay content, the lesser the liquid flowback. Some samples have high clay content. However, it has high flowback rate, which may account for good pore connection. Through the above study, the flowback rate has negative relationship with clay content and positive relationship with pore size, pore connection, and displacement pressure. In order to increase tight gas production in the study area, the formation should have high flowback rate and less liquid retention. Therefore, clay expansion preventing additives should be added into the fracturing liquid to reduce the liquid retention. The quick flowback should be implemented after hydraulic fracturing for reducing the interaction between liquid and rock. At the same time, the drawdown pressure should keep in a certain value to reduce stress sensitivity.

The microscopic interaction mechanism between working fluids and shale reservoirs is the key basic issue for the efficient development of shale gas. The initial water saturation of clay-rich shale is low, and the water absorption through strong chemical osmosis is an important factor for the wellbore instability of the drilling fluid filtration loss and the low flowback rate of hydraulic fracturing. Membrane efficiency is a key parameter in evaluating the mechanical-chemical coupling of shale-fluid interaction. Because microcracks develop in reservoir shale, pressure transfer experiments are no longer capable of obtaining membrane efficiency value. In this paper, the characteristics of shale water saturation are considered. The model calculating membrane efficiency is obtained, and the shale membrane efficiency of the reservoir studied, based on the triple-layer model of clay mineral-water interface electrochemistry. Membrane efficiency of unsaturated shale depends on the excess charge density of the surface of the solid in different water saturations. The analysis of factors influencing shale membrane efficiency in unsaturated reservoirs shows that the shale membrane efficiency decreases with the increase of water saturation under unsaturated conditions. The partition coefficient of counterion in the Stern layer, cation exchange capacity, and solute concentration in pore fluid will affect the membrane efficiency of unsaturated shale. The membrane efficiency of the reservoir section shale in Fuling area is calculated and analyzed, and the water-absorbing capacity by chemical osmosis of the reservoir interval shale is evaluated based on the membrane efficiency model of unsaturated shale.

In this study, research progress on critical liquid-carrying theory was introduced and its applicable conditions were presented and analyzed. The design technique of coiled-tubing drainage gas recovery was proposed, including the design method and calculation formula of diameter of coiled tubing, strength, and installation of a gas well Christmas tree, along with running time. Based on the design method, coiled-tubing drainage gas recovery technology was used in SD block of Sulige gas field to solve the problem of gas effusion. The field test results show a good effect of smaller pressure difference and higher gas production rate when the coiled-tubing drainage gas recovery method is used.

Water imbibition, conductivity measurements, and ion identification were performed to investigate ion diffusion behavior between slick water and shale for large-scale hydraulic fracturing. The results indicated that there was strong ion exchange between water and shale. The ion concentration in water increases with fracture complexity and is dependent on the salinity of fracturing fluids. This implies that fracturing effects could be forecast from flow-back fluid ion concentrations after large-scale slick water fracturing. Higher levels of ion diffusion imply the presence of larger fracturing areas and higher level of fracture density for a similar reservoir. The mechanism of ion diffusion and the corresponding effects on IOR (increased oil recovery) based on a field example are discussed.

The volcanic reservoir is an important kind of unconventional reservoir. The aqueous phase trapping (APT) appears because of fracturing fluids filtration. However, APT can be autoremoved for some wells after certain shut-in time. But there is significant distinction for different reservoirs. Experiments were performed to study the petrophysical properties of a volcanic reservoir and the spontaneous imbibition is monitored by nuclear magnetic resonance (NMR) and pulse-decay permeability. Results showed that natural cracks appear in the samples as well as high irreducible water saturation. There is a quick decrease of rock permeability once the rock contacts water. The pores filled during spontaneous imbibition are mainly the nanopores from NMR spectra. Full understanding of the mineralogical effect and sample heterogeneity benefits the selection of segments to fracturing. The fast flow-back scheme is applicable in this reservoir to minimize the damage. Because lots of water imbibed into the nanopores, the main flow channels become larger, which are beneficial to the permeability recovery after flow-back of hydraulic fracturing. This is helpful in understanding the APT autoremoval after certain shut-in time. Also, Keeping the appropriate production differential pressure is very important in achieving the long term efficient development of volcanic gas reservoirs.

To investigate the role of biomarkers in predicting postoperative liver dysfunction in patients with hepatocellular carcinoma (HCC).A total of 200 patients operated from July 2009 to June 2010 at Zhongshan Hospital, Fudan University for pathologically confirmed HCC were retrospectively analyzed for clinical data, HBD DNA level and serum biochemical markers for liver fibrosis. The patients were followed up to observersation end point. Correlation of the monitored parameters with postoperative liver dysfunction and patient survival was statistically analyzed.Preoperative hepatitis B virus (HBV) DNA level, serum prealbumin (PA) hyaluronic acid (HA), and laminin (LN) levels correlated with postoperative liver dysfunction, and preoperative LN level also was associated with the patients' survival. A predictive model was generated using these 4 parameters and validated in 89 HCC patients with sensitivity and specificity of 0.625 and 0.912, respectively [corrected]. However, no correlation was identified between postoperative liver function and overall survival.Liver fibrosis markers could be preoperatively used in predicting postoperative liver dysfunction in HCC patients.