Abstract: The present disclosure is directed to systems and methods for synthesizing a spidroin. In some embodiments, the methods comprise synthesizing a monomer in vivo in a heterologous host, the monomer comprising an N-terminus IntC domain and a C-terminus IntN domain, and post-translationally polymerizing the synthesized monomer via in vitro split-intein mediated polymerization.

Abstract: Methods and systems for determining one or more ion components. The method may include disposing a fluid sampling tool into a wellbore wherein the fluid sampling tool includes at least one probe to fluidly connect the fluid sampling tool to a formation in the wellbore, and at least one passageway that passes through the at least one probe and into the fluid sampling tool. The method may further comprise drawing a formation fluid, as a fluid sample, through the at least one probe and through the at least one passageway, and analyzing the fluid sample in the fluid sampling tool for one or more ion components.

Abstract: Disclosed herein are systems and methods to obtain representative reservoir fluid samples faster. In embodiments, the methods may include conveying a formation testing tool into a wellbore, pumping reservoir fluid from a downhole formation from the guard probe to at least one flow line at a first flow rate, pumping reservoir fluid from a downhole formation from the clean probe to a second flow line at a second flow rate, wherein a ratio of flow rates between the first flow rate and the second flow rate is held constant until reaching a first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe, changing the ratio of flow rates between the first and second flow rates, and sampling a reservoir fluid when reaching a second pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Abstract: Aspects of the subject technology relate to systems, methods, and computer readable media for determining permeability anisotropy of a formation. A formation tester can be set at a location within a wellbore. A plurality of probes can be set into a formation at the location. A tracer solution can be injected into the formation. A fluid can be continuously withdrawn from the formation over a time interval through at least one of the plurality of probes. The fluid can comprise a volume of the tracer solution into the formation. A changing concentration of the tracer solution that is withdrawn from the formation over the time interval can be measured based on the volume of the tracer solution that is withdrawn from the formation over the time interval. A permeability anisotropy of the formation can be determined based on the changing concentration of the tracer solution.

Abstract: Systems and methods are provided for determining ion concentration of a fluid downhole using a polymer matrix packaged in a cartridge. An example method can include disposing a cartridge within a flow path of a sensor. The cartridge includes a bracket; a retainer formed of a porous material having pores sized to allow a fluid to flow therethrough; and a substrate comprising a polymer matrix embedded with an ion-indicator, the substrate configured to interact with the fluid and to modify an optical characteristic of the substrate according to an ion concentration of the fluid. The method further includes illuminating the substrate; detecting a change in an optical characteristic of the substrate, the change indicative of the ion concentration of the fluid; and determining the ion concentration of the fluid.

Abstract: A method comprises receiving a measurement of a pressure in a subsurface formation at a number of depths in a wellbore formed in the subsurface formation across a sampling depth range of the subsurface formation to generate a number of pressure-depth measurement pairs. The method comprises partitioning the sampling depth range into a number of fluid depth ranges, wherein each of the number of fluid depth ranges comprises a range where a type of reservoir fluid is present in the subsurface formation. The method comprises determining a fluid gradient for the type of the reservoir fluid for each of the number of fluid depth ranges.

Abstract: Disclosed herein are systems and methods to obtain representative reservoir fluid samples faster. In embodiments, a formation testing tool, which includes a probe and a fluid passageway, is conveyed in a wellbore and the probe is pressed against the wellbore to create a fluidic seal in between the formation and the fluid passageway. The reservoir fluid is then pumped from the formation to the fluid passageway. The probe comprises a rubber disposed on an outer perimeter of the probe and an inflatable barrier disposed between the rubber and a central area of the probe. After reaching a first pre-determined value of drilling fluid contamination, the inflatable barrier of the probe is inflated. Sampling of the reservoir fluid is performed after reaching a second value of drilling fluid contamination in the reservoir fluid pumped from the formation to the fluid passageway.

Abstract: Aspects of the subject technology relate to systems, methods, and computer readable media for determining permeability anisotropy of a formation. A formation tester can be set at a location within a wellbore. A plurality of probes can be set into a formation at the location. A tracer solution can be injected into the formation. A fluid can be continuously withdrawn from the formation over a time interval through at least one of the plurality of probes. The fluid can comprise a volume of the tracer solution into the formation. A changing concentration of the tracer solution that is withdrawn from the formation over the time interval can be measured based on the volume of the tracer solution that is withdrawn from the formation over the time interval. A permeability anisotropy of the formation can be determined based on the changing concentration of the tracer solution.

Abstract: A method and system for removing a filter cover. A system and method may comprise a downhole fluid sampling tool including a tool body; a flow port disposed on the tool body; a sample chamber disposed within the tool body and fluidly coupled to the flow port; a pump disposed within the tool body. In examples, the pump is configured to pump a fluid through the flow port into the sample chamber; a filter disposed on an inlet of the flow port, wherein the filter is configured to filter the fluid entering the flow port; and a removable filter cover configured to prevent fluid contact with the filter.

Abstract: A method may comprise disposing a downhole pressure sampling tool into a wellbore; calculating a prior distribution based at least in part on one or more proxy logs, moving the downhole pressure sampling tool to a first location in the wellbore, taking at least one measurement with the downhole pressure sampling tool at the first location in the wellbore, calculating a posterior distribution based at least in part on the at least one measurement and the prior distribution, identifying a second location based at least in part on the posterior distribution, and moving the downhole pressure sampling tool to the second location.

Abstract: An image processing method, an image processing apparatus, an electronic device, and a computer-readable storage medium, relating to the technical field of image processing are provided. The image processing method may include performing blur classification on pixels of an image to obtain a classification mask image; and determining a blurred area of the image based on the classification mask image.

Abstract: A neural network update method, a classification method and an electronic device thereof are provided. The neural network update method includes obtaining input data of the neural network; identifying an active neuron and an inactive neuron from among at least one neuron included in the neural network; and based on an information bottleneck of the at least one neuron, training the neural network based on the input data while maintaining information bottleneck of the active neuron.

Abstract: A fluid flow rate sensor. The fluid flow rate sensor comprises an elongated structure; a heating element installed into a first end of the elongated structure; a first temperature transducer coupled to an outside of the elongated structure at a first predefined location; a second temperature transducer coupled to the outside of the elongated structure at a second predefined location; and a control unit that is configured to turn the heating element on and off, to analyze a first temperature indication received from the first temperature transducer, to analyze a second temperature indication received from the second temperature transducer, to determine a flow rate of a fluid that is in intimate contact with the outside of the elongated structure based on analyzing the first temperature indication and the second temperature indication, and to output the flow rate via a communication line.

Abstract: Methods to identify fluid holdups during downhole fluid sampling operations includes obtaining, using a sampling tool positioned within a wellbore, one or more fluid measurements using at least one sensor having a first set of spatial resolution, obtaining one or more second fluid measurements having a second spatial resolution, calculating a first fluid ratio using the at least one sensor having the first set of spatial resolution measurements, calculating a second fluid ratio of the second fluid measurements using the at least one sensor having the second set of spatial resolution, wherein the second set of spatial resolution is lower than the first set of spatial resolution, and identifying fluid holdup within the sampling tool when the differences between the two fluid ratios are higher than a limit or a similarity of the two fluid ratios are lower than a limit.

Abstract: Systems and methods for determining a level of contamination of a formation fluid by a drilling fluid are disclosed. The method includes defining a first curve of a range of values for a plurality of properties of the formation fluid in a multidimensional space, wherein each dimension is associated with one of the plurality of properties, defining a first point of the values of the plurality of properties for the drilling fluid in the multidimensional space, accessing measurements of the plurality of properties for a plurality of samples of a fluid being pumped out of a wellbore, defining a plurality of second points of the respective measured properties in the multidimensional space, and defining a vector from the first point through the plurality of second points to the first curve.

Abstract: The present disclosure provides a heat exchange system, air conditioning apparatus and control method for air conditioning apparatus. The heat exchange system including a compressor; a four-way valve; a first heat exchanger; a throttle device; a second heat exchanger; a fluid reservoir, including a first communication port and a second communication port, and the first communication port is communicated with the suction port, and the second communication port is communicated with one end of the second heat exchanger; a first valve body, being arranged on a flow path between the fluid reservoir and the compressor; a second valve body, being arranged on a flow path between the second communication port of the fluid reservoir and the throttle device; and a detection device, being used to detect the refrigerant amount for heat exchange cycle in the heat exchange system.

Abstract: A method and system for correlating two or more logs. The method may include reviewing an openhole log to identify one or more depths within a wellbore for testing, disposing a fluid sampling tool into the wellbore, creating a correlation log with the fluid sampling tool, depth-matching the correlation log to the openhole log to create a relative shift table, and moving the fluid sampling tool to the one or more depths within the wellbore based at least in part on the relative shift table. The system may include a fluid sampling tool disposed in a wellbore to create a correlation log and an information handling system connected to the fluid sampling tool.

Abstract: Systems and methods are provided for determining the wideband spectrum of downhole fluids based on downhole optical measurements. In some aspects, a plurality of optical data measurements associated with a subsurface fluid can be obtained from a subsurface optical measurement device. In some cases, a comparison can be made between the plurality of optical data measurements associated with the subsurface fluid and one or more sets of optical data stored in an optical data library. In some examples, the one or more sets of optical data can correspond to a plurality of different fluid samples. In some instances, a first fluid sample from the plurality of fluid samples that corresponds to at least a portion of the subsurface fluid can be identified based on the comparison. In some aspects, an absorbance spectrum of the subsurface fluid can be determined based on the first fluid sample.

Abstract: Aspects of the subject technology relate to systems, methods, and computer readable media for determining permeability anisotropy of a formation. A formation tester can be set at a location within a wellbore. A plurality of probes can be set into a formation at the location. A tracer solution can be injected into the formation. A fluid can be continuously withdrawn from the formation over a time interval through at least one of the plurality of probes. The fluid can comprise a volume of the tracer solution into the formation. A changing concentration of the tracer solution that is withdrawn from the formation over the time interval can be measured based on the volume of the tracer solution that is withdrawn from the formation over the time interval. A permeability anisotropy of the formation can be determined based on the changing concentration of the tracer solution.

Abstract: Aspects of the subject technology relate to systems, methods, and computer readable media for determining a parameter of a formation based on withdrawal of an injected tracer solution. A changing concentration profile of a volume of tracer solution that is withdrawn from a formation is measured. A varying simulated concentration profile associated with the tracer solution in a simulated formation is generated by modifying simulated formation parameters of the simulated formation. The varying simulated concentration profile is compared to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation. A parameter of the formation is identified based on a comparison of the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution withdrawn from the formation.