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Objective: Efficacy and safety of perampanel monotherapy for treating focal‐onset seizures (FOS) has been barely studied in China. This observational study aimed to evaluate the efficacy and safety of perampanel monotherapy in treating Chinese patients with FOS. Methods: This single‐center, prospective, real‐world observational study enrolled patients aged ≥4 years with FOS who visited the Epilepsy Out‐Patient Clinic of Nanjing Brain Hospital affiliated to Nanjing Medical University from January 2020 to December 2021. All patients were treated with perampanel monotherapy. Seizure‐freedom rates after 6 and 12 months of treatment were calculated. Adverse events (AEs) were recorded. Results: Seventy patients with FOS were enrolled. The mean maintenance perampanel dose was 4.64 ± 1.55 mg/day. The 6‐ and 12‐month retention rates of perampanel monotherapy were 78.6% (55/70) and 70.0% (49/70), respectively. The 6‐ and 12‐month seizure‐freedom rates were 69.84% (44/63) and 65.08% (41/63), respectively. Patients with focal to bilateral tonic–clonic seizures had significantly higher 6‐month and numerically higher 12‐month seizure freedom rates than patients with focal impaired awareness seizures (P = 0.046 and P = 0.204, respectively). Twenty‐six (37.1%) patients experienced treatment‐emergent AEs, and the most common AE was dizziness. Four (5.7%) patients withdrew from the study due to AEs. No new safety concern was observed. Significance: This is the first prospective study on the efficacy and safety of perampanel monotherapy in treating Chinese patients with FOS, and perampanel monotherapy was effective and safe in treating Chinese patients aged ≥4 years with FOS up to 12 months. More multicenter, real‐world studies with large sample sizes and longer follow‐ups are needed to further evaluate the long‐term efficacy and safety of perampanel monotherapy. [ABSTRACT FROM AUTHOR]

Permeability estimation and quantitative evaluation of pore microstructure have always been hotspots and difficulties in tight sandstone reservoirs research. Taking the fractal dimension as the breakthrough, 10 core samples of Chang 7 section in the Upper Triassic Yanchang Formation were collected from different wells in Longdong area of Ordos Basin. The fractal dimension was calculated by mercury intrusion capillary pressure curve which can be obtained from high pressure mercury injection experiment, and samples were divided into four groups as group I, II, III and IV according to the value of fractal dimension estimated. The observation of casting thin sections and field emission scanning electron microscope show that group I mainly has dissolved-intergranular pores and original intergranular pores, group II is mainly dissolved-intergranular pores, group III mainly has dissolved-intragranular pores, and group IV is mainly micropores in clay matrix. Meanwhile, there is a highly correlation between the fractal dimension and the reservoir physical properties. With the fractal dimension of tight sandstone samples approaching 3, the compaction and cementation show a gradual increase, while the pore sorting, physical parameters and percolation capacity display a gradual decrease. Through multiple regression analysis, a set of empirical equations based on the fractal dimension and different pore throat radius were constructed, in which the equation based on maximum permeability contribution radius has the highest correlation. It shows that micropore (0.1–0.2 μ m) contributes most to permeability in tight sandstone reservoir. 10 blind samples were included in regression analysis to improve the prediction accuracy of the new model. A total of 28 samples, including 8 referenced data, were used to verify the predictive accuracy of the new model. The new empirical equation can predict the permeability of tight sandstone relatively accurate. Thus, the fractal dimension can effectively predict the permeability and evaluate the quality of tight sandstone reservoirs. Image 1 • The fractal dimension value is closer to 2, the physical properties are better. • The pore radius of the maximum contribution to permeability is highly correlated with permeability. [ABSTRACT FROM AUTHOR]

Highlights • Cumulative-In-Situ-Injection-Production is a novel method for reservoir development. • Simulation results indicate CIIP is an efficient energy-supplement method. • CIIP is applicable to many kinds of tight reservoirs with highly irregular fractures. • Technology for Electric fluid regulation system of CIIP still need to be improved. Abstract Water flooding and gas injection are two traditional secondary development methods for tight oil reservoirs. Water injection has the problem of small injectivity due to low permeable reservoir matrix while gas injection brings about severe breakthrough because of obvious viscosity difference between gas and oil. These traditional approaches that supplement energy between wells are not highly effective. To fill this gap, this paper proposes an efficient energy-supplement method, continuous in-situ injection and production (CIIP), among fractures for multistage fractured horizontal well (MFHW) in tight oil reservoirs. CIIP divides hydraulic fractures into two kinds, in which odd fractures are used for production while even fractures are for injection. CIIP has three main advantages over traditional water flooding: firstly, it switches displacement interval from between injection and production wells to between hydraulic fractures; secondly, CIIP has a better injectivity compared to traditional water flooding at the same injection pressure; and thirdly, CIIP improves sweep efficiency thereby improving oil recovery. In this paper, a workflow is developed to evaluate the performance of CIIP in a case study. Reservoir properties and micro-seismic (MS) mapping data are analyzed to provide fundamental parameters for building a numerical simulation model, and then history matching is achieved to validate the model. The simulation considers two scenarios of hydraulic fractures: the uniform and non-uniform fractures. Uniform-fracture simulation aims to investigate the mechanisms of CIIP under three fracture models; different fracture half-lengths and the situation of existing high permeable channels between injection and production fractures are also included in uniform-fracture simulation. Non-uniform-fracture simulation, whose fractures are interpreted according to MS mapping results, is devised to demonstrate CIIP's superiority in a realistic way. This study is based on a theoretical approach and the results wait to be further proven in the field. Simulation results demonstrate that CIIP is an efficient energy-supplement method. It helps to maintain reservoir pressure near the initial condition during the thirty-year simulation. Meanwhile, even if ten injection wells are added, CIIP still injects 55% more water than water injection (WI) at the same injection pressure. Uniform-fracture simulation indicates that CIIP has a 2.23% more oil recovery than WI and a 3.74% than depletion. Besides, the influence of high permeable channels between injection and production fractures is insignificant and we can still expect CIIP's good performance when hydraulic fractures hit local natural fractures. The non-uniform-fracture simulation demonstrates that CIIP performs well too when hydraulic fractures are randomly distributed. It also finds outs that the presence of primary fractures in which proppant concentrates is essential to CIIP while the role of natural fractures is trivial compared to the hydraulic fractures. In a word, CIIP is a promising technology for tight oil reservoir development. [ABSTRACT FROM AUTHOR]

The Triassic Chang 6 Member sandstones are important oil reservoirs in the Ordos Basin of north-western China, and are actually considered to be typical tight sandstone reservoirs. Diagenetic alterations play a prominent role in considerably impacting the reservoir quality. In this study, an integrated approach of: thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), cathodoluminescence (CL), fluid inclusions, laser Raman spectrographic analysis, and stable isotope analysis was applied to examine the diagenetic history recorded in the Chang 6 tight sandstones and investigate the influences of diagenesis on reservoir quality. The sandstones consist of fine-grained, moderated-to-well sorted arkoses (Q 48.5 F 40.9 R 10.6) and lithic arkoses (Q 54.3 F 29.1 R 16.6) with an average porosity and permeability of 9.10% and 0.39 mD, respectively. The sandstones have undergone complex diagenetic processes; dominant eogenetic features include: (ⅰ) mechanical compaction, (ⅱ) leaching of feldspar in meteoric water, (ⅲ) chlorite coats originating from the transformation of precursor clays and precipitating directly from interstitial water, (ⅳ) calcites filling intergranular pores as poikilotopic cements, and (ⅴ) quartz and albite overgrowths on surfaces of grains. Subsequent mesogenetic events include: (ⅰ) ankerite cements filling porosity and replacing framework grains, (ⅱ) extensive dissolution of feldspars and precipitation of kaolinites due to emplacement of organic acids, and (ⅲ) secondary quartz overgrowths in the late period of mesogenesis. Early calcite is characterized by 13C (δ13C PDB ranging from −3.45‰ to −0.30‰, mean = −2.00‰) and 18O (δ18O PDB varying from −16.70‰ to −5.80‰, mean = −10.50‰), while late ankerite is rich in 12C (δ13C PDB ranging from −10.71‰ to 0.80‰, mean = −3.58‰) and 16O (δ18O PDB varying from −24.30‰ to −15.80‰, mean = −19.93‰). Moreover, calcite hosts single liquid fluid inclusions, two-phase fluid inclusions are contained in ankerite cements (with mean homogenization temperature (Th) of 96.0 °C and salinity estimates from 11.47 to 18.96 eq. wt.% NaCl). These data indicate that the calcite originated from meteoric water and the ankerite was associated with organic matter and recrystallization of the early calcite cements. Furthermore, the metallic ions such as Fe2+, Mg2+, and Ca2+ required for ankerite precipitation were produced through alterations of volcanic fragments, feldspars, and biotites. In comparison, compaction has more important role than cementation in the loss of original porosity although cementation exerts enormous influence on reducing porosity. Quantitatively, the compactional porosity loss reaches 54.9%, while the cementation porosity loss accounts for up to 42.8%. Carbonate cements and the other authigenic products (quartz and albite overgrowth, and kaolinite) mostly fill intergranular pores, thus reduce porosity. Chlorite coats have effects in inhibiting compaction and restraining the development of quartz overgrowth, thereby protect the intergranular porosity to some extent. Early secondary porosity was enhanced by leaching and dissolution of feldspar in the eogenetic period. However, these processes did not increase the net porosity in the mesogenetic stage. • Reconstruct diagenetic history based on dynamic analysis and test data. • Interpret material sources of carbonate cement by isotope and petrologic data. • Estimate leaching and dissolution in different stages for net porosity improvement. • Discuss diagenetic events on tight sandstone reservoir quality quantitatively. [ABSTRACT FROM AUTHOR]

CO 2 flooding is believed as an effective and promising method to enhance oil recovery. However, for tight oil reservoirs of Long Dong (LD) region in Ordos Basin, CO 2 flooding cannot achieve miscible condition since reservoir pressure is lower than minimum miscibility pressure (MMP). Meanwhile, this region has abundant associated gas production. Impure CO 2 with associated gas re-injection at the near-miscible condition is a promising enhanced oil recovery (EOR) method which may solve the problem above. This study aims to investigate the oil recovery potential of this method by conducting experiments and simulations. Firstly, based on the reservoir condition (64 ℃), slim-tube experiments and simulations were performed to acquire correlations of pressure, interfacial tension (IFT) and oil recovery of pure CO 2 flooding. Then the MMP, the minimum near-miscible pressure (MNMP), and near-miscible region were determined. The pressure interval of the near-miscible region ranges from 17.82 MPa to 22.75 MPa. Secondly, the minimum CO 2 concentration for conducting impure CO 2 with associated gas re-injection at the near-miscible condition was investiaged, which is 73.3% for the target formation. Furthermore, by studying the composition of injected gas, it is found that the presence of methane and nitrogen impedes oil and gas to achieve the miscible or near-miscible phase. With the decrease of CO 2 concentration of injected gas by 10% or the concentration of impurities in the injected gas increases by 7% each time, MMP and NMMP increase by 1.08 MPa and 0.89 MPa, respectively. This study explores the feasible application of using impure CO 2 with associated gas re-injection to improve oil recovery for tight oil reservoirs. [ABSTRACT FROM AUTHOR]