Abstract: A method comprising: without removing a BHA from a wellbore of a well extending into a formation, extending, into an interior flow bore of the BHA, a first component of a wet latch assembly to provide an extended first component of the wet latch assembly; conveying downhole via a wireline cable, from a surface through an interior flow bore provided by a drill string, a second component of the wet latch assembly, and coupling the second component of the wet latch assembly with the extended first component of the wet latch assembly such that an electrical connection is established between the first component and the second component and between the BHA and the surface via the wireline cable; and testing the formation with a formation tester of the BHA, while providing power and/or data telemetry for the formation tester via the wet latch assembly and the wireline cable.

Abstract: A bottom hole assembly (BHA) comprising: a first component of a wet latch assembly, the first component configured for coupling, when extended into the interior flow bore of the BHA, with a second component of the wet latch assembly to provide an assembled wet latch assembly, such that an electrical connection can be made between the first component and the second component; and a formation tester operable for performing a formation test, the formation tester electrically connected with the first component of the wet latch assembly, such that power and/or telemetry can be provided to the formation tester via the assembled wet latch assembly during the formation test.

Abstract: A method may comprise positioning a downhole fluid sampling tool into a wellbore, performing a pressure test operation within the wellbore, performing a pumpout operation within the wellbore, identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation, and acquiring the clean fluid sample from the wellbore. A system may comprise a downhole fluid sampling tool and an information handling machine. The downhole fluid sampling tool may further comprise one or more probes attached to the downhole fluid sampling tool, one or more stabilizers attached to the downhole fluid sampling tool, and a sensor placed in the downhole fluid sampling tool configured to measure drilling fluid filtrate.

Abstract: A method and system for performing a pressure test. The method may comprise inserting a formation testing tool into a wellbore to a first location within the wellbore, identifying one or more tool parameters of the formation testing tool, performing a first pre-test with the pressure transducer when the pressure has stabilized to identify formation parameters, inputting the formation parameters and the one or more tool parameters into a forward model, changing the one or more tool parameters to a second set of tool parameters; performing a second pre-test with the second set of tool parameters; and comparing the first pre-test to the second pre-test. A system may comprise at least one probe, a pump disposed within the formation testing tool, at least one stabilizer, a pressure transducer disposed at least partially in the at least one fluid passageway, and an information handling system.

Abstract: A focused sampling method comprising: allocating fluid flow from a guard zone through a guard line and from a sample zone through a sample line, the guard zone being positioned at least partially concentrically about the sample zone and the guard zone, and the sample zone being in fluid communication with a formation; pumping, via a common line, a combined fluid flow from the formation through to a discard line for a pre-sampling time period, the combined flow comprising the fluid flow allocated from the guard zone into the guard line and the fluid flow allocated from the sample zone into the sample line; subsequent the pre-sampling time period, discontinuing flow from the guard line into the common line, such that the combined flow comprises only the fluid flow from the sample line; and introducing the combined flow comprising the fluid flow from the sample line into a sample chamber.

Abstract: Disclosed are systems and methods for performing a contamination estimation of a downhole sample comprising at least a formation fluid and a filtrate. 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. A principle component analysis (PCA) is performed on the fused multivariate dataset to determine optical and density properties of the formation fluid. Based on at least the PCA, optical and density properties of the filtrate are determined. From the optical and density properties of the formation fluid and of the filtrate, a multivariate calculation is performed to generate concentration profiles of the formation fluid and the filtrate.

Abstract: A coring tool includes a coring bit to cut and detach a core sample from a subsurface formation formed in a borehole. The coring tool includes a pressure vessel that includes a core chamber to store the core sample at a pressure and a piston positioned adjacent to the core chamber. The pressure vessel includes a chamber adjacent to the piston and a gas reservoir to store a gas that expands as the gas is moved to a surface of the borehole. The pressure vessel includes a valve coupled to an inlet of the chamber and an outlet of the gas reservoir, wherein the gas is to flow into the chamber when the valve is open to move the piston to cause an increase in the pressure of the core chamber.

Abstract: Disclosed are methods, systems, and devices for measuring and otherwise processing core samples. In some embodiments, a method includes containing a core sample in a containment vessel including dynamically adjusting pressure within the containment vessel to maintain a phase of fluid within the core sample. Pressure is reduced within the containment vessel. During pressure or following reduction, one or more properties of the fluid in the core sample are measured.

Abstract: Disclosed herein are examples embodiments of a progressive modeling scheme to enhance optical sensor transformation networks using both in-field sensor measurements and simulation data. In one aspect, a method includes receiving optical sensor measurements generated by one or more downhole optical sensors in a wellbore; determining synthetic data for fluid characterization using an adaptive model and the optical sensor measurements; and applying the synthetic data to determine one or more physical properties of a fluid in the wellbore for which the optical sensor measurements are received.

Abstract: Systems and procedures for implementing radiometric calibration are disclosed. In some embodiments a radiometry system includes a light source that generates light. The radiometry system further includes a transmissive diffuser configured to receive the light and comprising a first translucent element having a surface and/or internal diffusion structure that substantially scatters the light. An optical detector is configured to receive and detect diffused light from the transmissive diffuser.

Abstract: The present application relates sensing reactive components in fluids by monitoring band gap changes to a material having interacted with the reactive components via physisorption and/or chemisorption. In some embodiments, the sensors of the present disclosure include the material as a reactive surface on a substrate. The band gap changes may be detected by measuring conductance changes and/or spectroscopic changes. In some instances, the sensing may occur downhole during one or more wellbore operations like drilling, hydraulic fracturing, and producing hydrocarbons.

Abstract: A method may comprise sampling a wellbore fluid; analyzing the wellbore fluid and determining a presence of a graphene-like substrate, a concentration of the graphene-like substrate, or both, in the wellbore fluid; and correlating the presence and the concentration of the graphene-like substrate to at least one subterranean formation characteristic.

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: A system comprising (i) thin film optical element comprising substrate and thin film stack (?2 film layers; uniform thickness—variation of less than ±5% in any 10 mm2 stack) deposited on substrate's first side; (ii) holder comprising at least one opening; wherein holder has inner side and outer side having beveled edge extending into lip having flat side and beveled edge side; wherein beveled edge/beveled edge side of lip form angle <45° with flat side of lip/first side; wherein flat side of lip and holder inner side define socket receiving substrate; wherein opening exposes first side to deposition plume; wherein first side contacts flat side of lip, thereby allowing film stack deposition on first side; wherein beveled edge side/beveled edge provide film uniformity, and (iii) deposition source providing plume traveling towards first side perpendicular to flat side of lip/first deposition side; and wherein beveled edge side faces plume.

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: A system to determine a contamination level of a formation fluid, the system including a formation tester tool to be positioned in a borehole, wherein the borehole has a mixture of the formation fluid and a drilling fluid and the formation tester tool includes a sensor to detect time series measurements from a plurality of sensor channels. The system includes a processor to dimensionally reduce the time series measurements to generate a set of reduced measurement scores in a multi-dimensional measurement space and determine an end member in the multi-dimensional measurement space based on the set of reduced measurement scores, wherein the end member comprises a position in the multi-dimensional measurement space that corresponds with a predetermined fluid concentration. The processor also determines the contamination level of the formation fluid at a time point based the set of reduced measurement scores and the end member.

Abstract: An optical device fabrication system includes a witness sample having a roughened backside that is capable of both optical transmission and ellipsometry measurement analysis. The optical device can be an integrated computing element core.

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: A method and system for measuring drilling fluid filtrate. The method may comprise disposing a downhole fluid sampling tool into a wellbore at a first location, activating a pump to draw a solids-containing fluid disposed in the wellbore into the downhole fluid sampling tool, drawing the drilling fluid with the pump across the at least one filter to form a drilling fluid filtrate, drawing the drilling fluid filtrate with the pump through the channel to the at least one sensor section, and measuring the drilling fluid filtrate with the at least one sensor. A system may comprise a downhole fluid sampling tool. The downhole fluid sampling tool may comprise at least one multi-chamber section, at least one sensor section, at least one filter, a pump, and a channel.

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.