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: A key block can be generated from a session key used by a computer-based design tool for a circuit design by encrypting the session key using computer hardware. The key block can be divided, by the computer hardware, into a plurality of sub-blocks. A plurality of enhanced sub-blocks can be generated by the computer hardware by encrypting each sub-block of the plurality of sub-blocks with a different key of a plurality of keys corresponding to a plurality of Intellectual Property (IP) cores of the circuit design. The plurality of enhanced sub-blocks can be stored in a memory.

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.

Abstract: An image display method, an image processing method, an image processing device, a display system, and a computer-readable storage medium are disclosed. The image processing method is applied to an image processing device and includes: determining a first region in an original image; performing first processing on the first region in the original image to obtain a first processed region; performing second processing on the original image to obtain a second processed region; generating a first image based on the first processed region and the second processed region. A resolution of the first processed region is greater than a resolution of the second processed region.

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: 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: A method and system for performing a pressure test. The method may include inserting a formation testing tool into a wellbore to a first location within the wellbore based at least in part on a figure of merit. The formation testing tool may include at least one probe, a pump disposed within the formation testing tool and connect to the at least one probe by at least one probe channel and at least one fluid passageway, and at least one stabilizer disposed on the formation testing tool. The method may further include activating the at least one stabilizer, wherein the at least one stabilizer is activated into a surface of the wellbore and performing the pressure test and determining at least one formation property from the pressure test.

Abstract: The subject disclosure relates to techniques for correcting logging depth of a well bore. A process of the disclosed technology can include receiving a first sensor measurement from a first sensor disposed in a wellbore, receiving a second sensor measurement from a second sensor disposed in the wellbore, wherein the first sensor and the second sensor are disposed on a wireline with a predetermined distance between the first sensor and the second sensor, generating a correlation function based on the first sensor measurement and the second measurement, and determining, based on the correlation function, whether the measurements indicate a perceived distance between the first sensor and the second sensor deviating from the predetermined distance.

Abstract: A method includes receiving first material property data for a first material in one or more second materials, detecting material sensor data from at least one sensor, and applying an inverse model and a forward model to the first material property data to provide, at least in part, synthetic sensor measurement data for the one or more second materials.

Abstract: An optical element may be fabricated by applying foreign or attenuating material, for example, a copper material or a material that includes copper, to a silicon dioxide thin film to form a layer that exhibits extraordinary optical absorption in the infrared wavelength region of at or about 2500-4700 nanometers. The foreign material may comprise or include a transition metal. The optical element exhibits increased accuracy and sensitivity in the infrared wavelength region of at or about 2500-4700 nanometers. The at or about 2500-4700 nanometers absorption property of the optical element can be selectively tuned to any region within this at or about 2500-4700 nanometers wavelength region. The optical element may comprise multiple layers of varying thicknesses to further tune the optical element to one or more spectral bands. Such an optical element may be utilized in a formation fluid analysis tool or an eye protection device.

Abstract: Fluid holdups within a downhole sampling tool are identified by comparing high- and low-resolution measurements of fluid samples.

Abstract: A downhole fluid sampling tool may include: 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, wherein 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: Systems and methods for performing a contamination estimation of a downhole sample comprising at least a formation fluid and/or a filtrate are provided. A plurality of downhole signals are obtained from the downhole sample and one or more of the signals are conditioned. At least two of the conditioned signals or downhole signals are fused into a multivariate dataset. From optical and density properties of the formation fluid and/or of the filtrate, a multivariate calculation is performed to generate concentration profiles of the formation fluid and the filtrate.

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: 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: Light from a light source that has interacted with a sample of downhole fluid provided in a downhole optical tool is sequentially passed through a plurality of groups of light filters, each of the groups of light filters including of one or more light filters, to generate a data set for each of the groups of light filters, also referred to as a simultaneous channel group. The data generated for each of the simultaneous channel groups is then analyzed to determine if the data from that simultaneous channel groups is effective in providing information useful for the analysis of the sample of downhole fluid.