Abstract: An apparatus includes a processor and a machine-readable medium having program code to cause the apparatus to obtain a first dictionary based on a first training set of signals and determine a first subset of the first training set of signals based on a training reconstruction accuracy threshold and the first dictionary, wherein each atom in the first dictionary includes at least one of a signal pattern and a function representing the signal pattern. The program code also includes code to generate a second dictionary based on a second training set of signals, wherein the second training set of signals includes the first subset of the first training set of signals.

Abstract: The subject disclosure provides for a method of optical sensor calibration implemented with neural networks through machine learning to make real-time optical fluid answer product prediction adapt to optical signal variation of synthetic and actual sensor inputs integrated from multiple sources. Downhole real-time fluid analysis can be performed by monitoring the quality of the prediction with each type of input and determining which type of input generalizes better. The processor can bypass the less robust routine and deploy the more robust routine for remainder of the data prediction. Operational sensor data can be incorporated from a particular optical tool over multiple field jobs into an updated calibration when target fluid sample compositions and properties become available.

Abstract: Systems, methods, and computer-readable media for detecting downhole environment characteristics. An optical sensor is deployed to a downhole environment. Optical signal data received from the deployed optical sensor is received by a model configured to determine downhole environment characteristics directly from optical signal data. The model determines a downhole environment characteristic from the optical signal data and provides the determined characteristic to a user.

Abstract: Mutual-complementary modeling and testing methods are disclosed that can enable validated mapping from external oil and gas information sources to existing fluid optical databases through the use of forward and inverse neural networks. The forward neural networks use fluid compositional inputs to produce fluid principal spectroscopy components (PSC). The inverse neural networks apply PSC inputs to estimate fluid compositional outputs. The fluid compositional data from external sources can be tested through forward models first. The produced PSC outputs are then entered as inputs to inverse models to generate fluid compositional data. The degree of matching between reconstructed fluid compositions and the original testing data suggests which part of the new data can be integrated directly into the existing database as validated mapping. The applications of using PSC inputs to reconstruct infrared spectra and estimate oil-based-mud (OBM) contamination with endmember spectral fingerprints are also included.

Abstract: Quality factors associated with formation pressure measurements at various depths in the geologic formation are determined based on one or more well logs of formation properties in a geologic formation. A formation testing tool with two or more probes is positioned in a borehole of the geologic formation based on the quality factors. The two or more probes in the borehole perform respective formation pressure measurements, where each formation pressure measurement is performed at a different depth. The formation pressure measurements and the given distance between the two or more probes indicate a formation pressure gradient.

Abstract: A method and system for estimating clean fluid composition and properties. A method may comprise disposing a downhole fluid sampling tool into a wellbore, wherein the downhole fluid sampling tool comprises optical instrumentation, obtaining a fluid sample with the downhole fluid sampling tool, wherein the fluid sample comprises a reservoir fluid contaminated with a well fluid, identifying input parameters from at least one sensor response on the optical instrumentation, and predicting a clean fluid sample of the reservoir fluid using an asymptote of a dimensional reduction analysis and equation of state. A system may comprise a downhole fluid sampling tool and a processing unit. The downhole fluid sampling tool may further comprise an optical instrumentation operable to obtain fluid samples of a reservoir fluid contaminated with a well fluid while the downhole fluid sampling tool is disposed in a wellbore.

Abstract: Data deduplication techniques may use a fingerprint hash table and a backend location hash table in connection with performing operations including fingerprint insertion, fingerprint deletion and fingerprint lookup. Processing I/O operations may include: receiving a write operation that writes data to a target logical address; determining a fingerprint for the data; querying the fingerprint hash table using the fingerprint to determine a matching entry of the fingerprint hash table for the fingerprint; and responsive to determining that the fingerprint hash table does not have the matching entry that matches the fingerprint, performing processing including: inserting a first entry in the fingerprint hash table, wherein the first entry includes the fingerprint for the data and identifies a storage location at which the data is stored; and inserting a second entry in a backend location hash table, wherein the second entry references the first entry.

Abstract: A device including a sample cell configured to interact a fluid sample with an ion selective substrate to modify an optical characteristic of the ion selective substrate according to an ion concentration of the fluid sample is provided. The sample cell is configured to optically interact an illumination light with the ion selective substrate to generate a sample light. The device includes an integrated computational element configured to interact with the sample light to provide a modified light that has a property indicative of the ion concentration in the fluid sample; and a detector that receives the modified light and provides an electrical signal proportional to an intensity of the modified light.

Abstract: An apparatus includes a subsurface sensor for use in a borehole to provide a subsurface measurement series, a subsurface processor to receive the subsurface measurement series, and a machine-readable medium. The machine-readable medium has program code to cause the apparatus to obtain the subsurface measurement series and generate an atom combination based on the subsurface measurement series using the subsurface processor, wherein the atom combination comprises a subset of atoms from a dictionary. The code also has instructions to generate a set of characterizing values and transmit the set of characterizing values to a different physical location, wherein the set of characterizing values comprises an atom identifier and at least one corresponding atom weight for at least one atom from the atom combination.

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 method for producing a metal-plastic composite component comprises: forming a metal substrate with a receiving hole; injecting first plastics into the metal substrate to form a metal-plastic blank, wherein the first plastics are filled in the receiving hole; processing the receiving hole and the first plastics for removing a part of the first plastics by at least one cutter to form a receiving space; and injecting second plastics into the metal-plastic blank to form the metal-plastic composite component, wherein the receiving space is filled with the second plastics. With this method, a combination strength of the metal-plastic composite component is enhanced. A metal-plastic composite component is also provided.

Abstract: A system for conducting real-time chemical analysis of deposits is provided. The system includes an electromagnetic radiation source positioned on a downhole tool that emits electromagnetic radiation to a surrounding downhole environment within a field of view of interest. The system also includes a multivariate optical element positioned on the downhole tool that has optical filters configured to receive reflected radiation from the field of view of interest and generate respective filtered radiation signals. Each of the optical filters has a different transmission function that corresponds to a respective chemical species of interest. The system also includes an image sensor positioned on the downhole tool that detects each of the respective filtered radiation signals from the multivariate optical element. The image sensor provides image information of the field of view of interest that indicates a presence of at least one chemical species of interest located in the surrounding downhole environment.

Abstract: The disclosure discloses an algebraic decoding method and a decoder for a (n, n(n?1), n?1) permutation group code in a communication modulation system. The basic principle of the decoding method is: assuming that two code elements p(r1)=s1 and p(r2)=s2 can be correctly detected in a received real vector with a length of n, including their element values s1, s2 and position indices r1, r2 in the vector, an intermediate parameter w is determined by solving an equation (r1?r2)w=(s1?s2)(mod n); and each code element is calculated by w according to p(i)=(s1+(n?r1+i)w)(mod n), i=1, 2, . . . , n. The decoder is mainly composed of multiple n-dimensional registers, a w calculator, n code element calculators, and a code element buffer. In the disclosure, in a case where a receiver only correctly detects two code elements in a transmitted codeword with a length of n, the codeword can be correctly decoded by using the received information of the two code elements.

Abstract: A method and system for estimating clean fluid composition and properties. A method may comprise disposing a downhole fluid sampling tool into a wellbore, wherein the downhole fluid sampling tool comprises optical instrumentation, obtaining a fluid sample with the downhole fluid sampling tool, wherein the fluid sample comprises a reservoir fluid contaminated with a well fluid, identifying input parameters from at least one sensor response on the optical instrumentation, and predicting a clean fluid sample of the reservoir fluid using an asymptote of a dimensional reduction analysis and equation of state. A system may comprise a downhole fluid sampling tool and a processing unit. The downhole fluid sampling tool may further comprise an optical instrumentation operable to obtain fluid samples of a reservoir fluid contaminated with a well fluid while the downhole fluid sampling tool is disposed in a wellbore.

Abstract: A method may include transforming optical responses for a fluid sample to a parameter space of a downhole tool. The optical responses are obtained using a first operational sensor and a second operational sensor of the downhole tool. Fluid models are applied in the parameter space of the downhole tool to the transformed optical responses to obtain density predictions of the fluid sample. The density predictions of the first operational sensor are matched to the density predictions of the second operational sensor based on optical parameters of the fluid models to obtain matched density predictions. A difference between the matched density predictions and measurements obtained from a densitometer is calculated, and a contamination index is estimated based on the difference.

Abstract: A method, including disposing a probe of a sensor system in a wellbore to interact with a formation fluid that includes a mud filtrate and a clean fluid that includes one of a formation water, or a formation hydrocarbon fluid including at least one hydrocarbon component. The method includes collecting multiple measurements of a formation fluid from a wellbore, the formation fluid comprising a mud filtrate and a clean fluid, is provided. The clean fluid includes at least one hydrocarbon component, and the method also include identifying a concentration of the mud filtrate and a concentration of the clean fluid in the formation fluid for one of the measurements, and determining at least one hydrocarbon composition and at least one physical property of the clean fluid based on a measurement fingerprint of the hydrocarbon components. A sensor system configured to perform a method as above is also provided.

Abstract: The disclosed embodiments include thin film multivariate optical element and detector combinations, thin film optical detectors, and downhole optical computing systems. In one embodiment, a thin film multivariate optical element and detector combination includes at least one layer of multivariate optical element having patterns that manipulate at least one spectrum of optical signals. The thin film multivariate optical element and detector combination also includes at least one layer of detector film that converts optical signals into electrical signals. The thin film optical detector further includes a substrate. The at least one layer of multivariate optical element and the at least one layer of detector film are deposited on the substrate.

Abstract: Quality factors associated with formation pressure measurements at various depths in the geologic formation are determined based on one or more well logs of formation properties in a geologic formation. A formation testing tool with two or more probes is positioned in a borehole of the geologic formation based on the quality factors. The two or more probes in the borehole perform respective formation pressure measurements, where each formation pressure measurement is performed at a different depth. The formation pressure measurements and the given distance between the two or more probes indicate a formation pressure gradient.

Abstract: The display control method according to some embodiments of the present disclosure includes: acquiring an M-primary-color input signal from each pixel in an original image, the original image including a plurality of pixels corresponding to the plurality of pixel units respectively, each pixel being configured to display a colored image in M primary colors, M being an integer greater than 1 and smaller than N; and calculating an N-primary-color input signal for a corresponding pixel unit of the N-primary-color display panel in accordance with color coordinates of each primary color for the N-primary-color display panel and the M-primary-color input signal.

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.