Correlation of retinal alterations with vascular structure of macular neovascularisation in swept-source optical coherence tomography angiography in age-related macular degeneration

Purpose The aim of this study was to find out whether the vascular architecture of untreated macular neovascularisations (MNV) in neovascular age-related macular degeneration (nAMD) as visualised with optic coherence tomography angiography (OCTA) is associated with functional and known morphological alterations of the retina in optic coherence tomography (SD-OCT). Methods The study design was retrospective with consecutive patient inclusion. In 107 patients with newly diagnosed nAMD, MNV were detected by means of OCTA and automated quantitative vascular analysis was performed. The MNV characteristics measured were area, flow density, total vascular length (sumL), density of vascular nodes (numN), fractal dimension (FD) and average vascular width (avgW). These parameters were assessed for associations with vision (BCVA), central retinal thickness (CRT), fluid distribution, the elevation of any pigment epithelial detachment (PED), the occurrence of subretinal haemorrhage and atrophy. Results BCVA was significantly worse with greater MNV area and sumL. Fluid distribution differed significantly in relation to area (p < 0.005), sumL (p < 0.005) and FD (p = 0.001). Greater PED height was significantly associated with higher numN (p < 0.05) and lower avgW (p < 0.05). Atrophy was present significantly more often in MNV with larger area (p < 0.05), higher sumL (p < 0.05) and higher flow density (p = 0.002). None of the MNV parameters had a significant association with CRT or the occurrence of haemorrhage. Conclusion OCTA is not restricted to evaluation of secondary changes but offers the opportunity to analyse the vascular structure of MNV in detail. Differences in vascular morphology are associated with certain secondary changes in retinal morphology. There are thus grounds for optimism that further research may identify and classify OCTA-based markers to permit more individualised treatment of nAMD.

Production Monitoring of Multilateral Wells by Quantum Marker Systems

Reliable information about the inflow composition and distribution in a multilateral well is of great importance and an existing challenge in the oil and gas industry. In this paper, we present an innovative method for dynamic monitoring of inflow profile based on quantum marker technology in a multi-lateral well located in West Siberia. Marker systems were placed in the well during the well reconstruction by horizontal side tracking with the parent borehole remaining in production. This way of reconstruction allows development of the reservoir drainage area with a lateral hole and bringing the oil reserves from the parent borehole into production, which results in an increased flow rate and improved oil recovery rate. Placement of marker systems into parent borehole and side-track for fluid distribution monitoring allows to evaluate the flow rate from every borehole and estimate the effectiveness of performed well reconstruction. Marker systems are placed into the parent borehole as a downhole sub installed into the well completion string. For the side-track polymer-coated marked proppant was injected during hydraulic fracturing to place markers. The developed method was reliably used for an accurate and fast determination of the inflow distribution in a multi-lateral well which allows more efficient field development and also enabled us to provide effective solutions for following challenges: Providing tools for timely water cut diagnostics in multilateral wells and information for water shut-off method selection; Selecting the optimal well operating mode for effective field development and premature flooding prevention in one or both boreholes; Evaluating whether well construction was performed efficiently, and an increased production rate was achieved; Leading to a considerable economic savings in capital expenditure.

The Understanding of Intertwined Physics: Discovering Capillary Pressure and Permeability Co-Determination

<p>Although capillary and permeability are the two most important physical properties controlling fluid distribution and flow in nature, the interconnectivity function between them was a pressing challenge. Because knowing permeability leads to determining capillary pressure. Geodynamics (e.g., subsurface water, CO2 sequestration) and organs (e.g., plants, blood vessels) depend on capillary pressure and permeability. The first determines how far the fluid can reach, while the second determines how fast the fluid can flow in porous media. They are also vital to designing synthetic materials and micro-objects like membranes and micro-robotics. Here, we reveal the capillary and permeability intertwined behavior function. And demonstrate the unique physical connectors: pore throat size and network, linking capillary pressure and permeability. Our discovery quantifies the inverse relationship between capillary pressure and permeability for the first time, which we analytically derived and experimentally proved.</p>

The Understanding of Intertwined Physics: Discovering Capillary Pressure and Permeability Co-Determination

<p>Although capillary and permeability are the two most important physical properties controlling fluid distribution and flow in nature, the interconnectivity function between them was a pressing challenge. Because knowing permeability leads to determining capillary pressure. Geodynamics (e.g., subsurface water, CO2 sequestration) and organs (e.g., plants, blood vessels) depend on capillary pressure and permeability. The first determines how far the fluid can reach, while the second determines how fast the fluid can flow in porous media. They are also vital to designing synthetic materials and micro-objects like membranes and micro-robotics. Here, we reveal the capillary and permeability intertwined behavior function. And demonstrate the unique physical connectors: pore throat size and network, linking capillary pressure and permeability. Our discovery quantifies the inverse relationship between capillary pressure and permeability for the first time, which we analytically derived and experimentally proved.</p>

Preliminary Evaluation of Zanubrutinib-Containing Regimens in DLBCL and the Cerebrospinal Fluid Distribution of Zanubrutinib: A 13-Case Series

Zanubrutinib is a second-generation Bruton’s tyrosine kinase inhibitor. Its safety and effectiveness in central nervous system (CNS) lymphoma along with its distribution in the brain and ability to cross the blood–brain barrier (BBB) remain unknown. This retrospective case series involved patients with diffuse large B-cell lymphoma (DLBCL) treated with zanubrutinib-containing regimens from August to December 2020 in PUMCH. The amounts of zanubrutinib in the plasma and brain were assessed by liquid chromatography–tandem mass spectrometry in paired plasma and cerebrospinal fluid (CSF) samples. In total, 13 patients were included: eight primary CNS lymphoma cases and five systemic DLBCL cases with 61.5% (8/13) refractory/relapsed and 84.6% (11/13) showing CNS involvement. The overall response rates were 84.5% in the entire population and 81.8% in the CNS-involved cases. A total of 23 time-matched plasma-CSF sample pairs were collected. The mean peak concentration of zanubrutinib in CSF was 2941.1 pg/ml (range, 466–9032.0 pg/ml). The corrected mean CSF/plasma ratio determined based on 94% protein binding was 42.7% ± 27.7% (range, 8.6%–106.3%). This preliminary study revealed the effectiveness of zanubrutinib-containing regimens in DLBLC, especially CNS-involved cases, for the first time. The excellent BBB penetration of zanubrutinib supports its further investigation for the treatment of CNS lymphoma.

Role of f(G) Gravity in the Study of Non-Static Complex Systems

The concept of complexity for dynamical spherically symmetric dissipative self-gravitating configuration [1] is generalized in the scenario of modified Gauss-Bonnet gravity. For this purpose, a spherically symmetric fluid with locally anisotropic, dissipative, and non-dissipative configuration is considered. We choose the same complexity factor for the structure as we did for the static case, while we consider the homologous condition for the simplest pattern of evolution. In this approach, we formulate structure scalars that demonstrate the essential properties of the system. A fluid distribution that fulfills the vanishing complexity constraint and proceeds homologously corresponds to isotropic, geodesic, homogeneous, and shear-free fluid. In the dissipative case, the fluid is still geodesic but it is shearing, and there is a wide range of solutions. In the last, the stability of vanishing complexity is examined.

High Performance Computing on the Cloud Successfully Deployed for 3D Geosteering and Reservoir Mapping While Drilling

The successful drilling of horizontal wells targeting reservoir zones of interest can be challenged by uncertainties in geological interpretation, identification of structure, and properties of reservoirs and fluid distribution. Optimizing the well placement of high-angle wells in order to intercept the sweet spots is crucial for the total hydrocarbon recovery in any development field. Thus, the geosteering domain was implemented to provide in real time a reservoir mapping characterization together with directional control to achieve the key performance objectives. In the past, many innovative technologies have been introduced in geosteering discipline, among them lately the deep EM directional resistivity tool that provides 1D formation resistivity mapping while drilling. However, despite the fact of delivering a multilayer mapping of the reservoir structure up to tens of meters away from wellbore, the real-time interpretation can be limited by this type of inversion. Since it is a 1D approach, these inversions map resistive boundaries on the vertical axis and assume infinite extend in all other directions. Consequently, in a complex geological setting, 1D approximation may fall short of properly describing the reservoir structure. This communication describes how the introduction of the 2D azimuthal resistivity inversions while drilling was conducted and details the various innovations required in the domains of downhole logging while drilling (LWD) measurements transmission in addition to adaptation of inversion methodology for real-time deployment, mainly through the use of high-performance cloud computing. The final enablement was the execution of automated workflows to process and deliver these advanced inversions into an integrated 3D geomodelling software within the turnaround time of drilling operations. This novel technology provides, while drilling, a better understanding of the 3D geological environment and fluid distribution with a deep depth of investigation, as well as the required information to make support for geosteering decisions for optimal well positioning. Initial field deployments were successfully conducted in horizontal wells, and three examples are presented here. Those real cases, executed with wire-drilled-pipe or mud-pulse telemetries, demonstrated the benefits of integrating 2D azimuthal inversions into the current geosteering workflow to provide a complete 3D structural understanding of the reservoir while drilling. This communication documents in detail how such an approach led to operational efficiency improvements in the form of 3D reservoir mapping in real-time, supporting a strategic change in the original well to turn toward the sweet spot, which was located sideways from the planned trajectory.

Hemodialysis Patients with Cardiovascular Disease Reveal Increased Tissue Na+ Deposition

Background: The relationship between Na+ balance and cardiovascular disease (CVD) in hemodialysis (HD) patients is not yet fully understood. We hypothesized that HD patients co-diagnosed with CVD show increased tissue Na+ accumulation compared to HD patients without CVD. Methods: In our observational study 52 HD patients were divided into a group with (23 subjects) or without (29 subjects) a positive history of cardiovascular events. We used 23Na-Magnetic Resonance Imaging (23Na-MRI) at 3.0 Tesla to quantify Na+ content in skin and muscle of both groups directly before and after HD. Additionally, total body fluid distribution was determined by Bioimpedance Spectroscopy (BIS) and laboratory parameters were assessed. Results: Compared to HD patients without CVD, 23Na-MRI detected an increased Na+ content in skin (21.7 ± 7.3 vs. 30.2 ± 9.8 arbitrary units, a.u., p < 0.01) and muscle tissue (21.5 ± 3.6 vs 24.7 ± 6.0 a.u., p < 0.05) in patients with previous CVD events. Simultaneously measured fluid amount by BIS, including excess extracellular water (1.8 ± 1.7 vs. 2.2 ± 1.7 L, p = 0.44), was not significantly different between both groups. Tissue Na+ accumulation in HD-CVD patients was paralleled by a higher plasma concentration of the inflammation marker Interleukin-6 (5.1, IQR 5.8 vs. 8.5, IQR 7.9 pg/ml, p < 0.05). Conclusion: In our cohort, HD patients with CVD showed higher tissue Na+ content than HD patients without CVD, while no difference in body water distribution could be detected between both groups. Our findings provide evidence that the history of a cardiovascular event is associated with disturbances in tissue Na+ content in HD patients.

Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach

In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.