Abstract: Process control for a pipeline can be adjusted based on spectroscopic measurements from a monitoring system. For example, a computing system can receive, from the spectroscopic monitoring system, a spectroscopic measurement with respect to fluid flow in the pipeline. The computing system can determine that an amount of a corrosive component in the fluid flow exceeds a predetermined threshold for the process control. In response to determining that the corrosive component in the fluid flow exceeds the predetermined threshold, the computing system can determine an adjustment to the process control for the fluid flow usable to maintain a compositional stability of the fluid flow. Then, the computing system can output the adjustment to a pipeline tool to maintain the compositional stability of the fluid flow.

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: Systems and methods for beam profile imaging by emitting a ray into one or more media; receiving a first signal corresponding to the ray at a first point; encoding a first matrix based at least in part on one or more of a location of the first point, a direction of the ray at the first point, and a first perturbation effect; receiving a second signal corresponding to the ray at a second point; encoding a second matrix based at least in part on one or more of a location of the second point, a direction of the ray at the second point, and a second perturbation effect; and calculating the value of the acoustic property of one or more media based at least in part on a comparison between the first matrix and the second matrix.

Abstract: Described herein are systems and techniques for monitoring for monitoring and evaluating conditions associated with a wellbore and wellbore operations that use neural operators instead of computationally intensive iterative differential equations. Such systems and techniques allow for determinations to be made as operations associated with a wellbore are performed. Instead of having to wait for computationally intensive tasks to be performed or take risks of proceeding with a wellbore operation without real-time evaluations being performed, these wellbore operations may be continued while determinations are timely made, thus improving operation of computing systems that perform evaluations and that make decisions regarding safely and efficiently performing wellbore operations such as drilling a wellbore, cementing wellbore casings in place, or injecting fluids into formations of the Earth.

Abstract: Described herein are systems and techniques for monitoring substances that are injected into an Earth formation whether that be CO2 from a carbon capture and storage (CCS) process, or water or steam injected for an enhanced oil recovery (EOR) process. Components located on an outside of a wellbore casing may be electrically isolated from components located on the inside of the wellbore casing. Data and/or power may be transferred through the wellbore casing wirelessly in order to increase the reliability of a data collection system because the need for wires to be placed on the outside surface of a wellbore casing is eliminated. The components located on the outside of the casing may receive electromagnetic (EM) or transmit EM fields as part of a system that collects data about substances that are injected into Earth formations during a CCS or EOR process.

Abstract: A method may comprise disposing a target rod in an insulating tube, wherein a first end of the target rod is in at least partial contact with the insulating tube, and disposing a target material geometry on a second end of the target rod, wherein the second end of the target rod is opposite the first end, and wherein the target material geometry comprises a target film and a barrier material.

Abstract: A monitoring system for monitoring a pipeline can include a sampling unit, a spectroscopy system, and a waste handling system. The sampling unit can include a sampling point for capturing a representative sample of a fluid flow in the pipeline. The spectroscopy system can be configured to chemically analyze the representative sample with respect to components of the fluid flow. Additionally, the spectroscopy system can be configured to detect a corrosive component of the fluid flow. The waste handling system can remove the representative sample from the spectroscopy system.

Abstract: A system for inspecting a tubular may comprise an electromagnetic (EM) logging tool and information handling system. The EM logging tool may further include a mandrel, one or more sensor pads attached to the mandrel by one or more extendable arms, and one or more partial saturation eddy current sensors disposed on each of the one or more sensor pads.

Abstract: A contrast device for analysis of a wellbore fluid includes: a substrate; and a contrast agent adhered to the substrate, wherein the contrast agent is configured to respond to an analyte within the wellbore fluid thereby altering a measurable characteristic of the contrast agent. A system including the contrast device may further include an energy source and a detector to facilitate measuring the characteristic of the contrast agent.

Abstract: Methods and systems disclosed may comprise: disposing a downhole tool into a subsurface formation; and embedding a contrast agent composition at a first position with the downhole tool, wherein the contrast agent composition reacts with at least one target subsurface fluid or gas migrating through or around a barrier forming one or more reaction products. In addition, methods and systems may comprise performing one or more formation logging measurements capable of detecting one or more reaction products with the downhole tool; and analyzing the one or more formation logging measurements for hydrogen leakage.

Abstract: Methods and or systems herein may be utilized for evaluating least one reactive component within a subsurface formation, comprising: disposing a downhole tool into the subsurface formation; introducing into the subsurface formation at a targeted depth a contrast agent composition. Further, methods and systems may be configured for performing one or more formation logging measurements capable of detecting one or more reaction products or byproducts or changes in the at least one reactive component within the subsurface formation fluid with the downhole tool. Additionally, methods and systems may be configured for analyzing the one or more formation logging measurements to at least one of confirm, characterize, presence, spatial distribution, and concentration of the reactive component within the subsurface formation fluid.

Abstract: Aspects of the subject technology relate to characterizing well casings non-invasively. An electrical current can be established in at least a portion of a casing in a target well through indirect electrification. An electric field component, a magnetic field component, or a combination thereof that is generated by the electrical current in the casing can be measured by one or more sensors. The measurements of the electric field component, the magnetic field component, or the combination thereof can be processed to estimate one or more properties of either or both the casing of the target well and a formation surrounding the target well.

Abstract: A method that includes disposing an acoustic logging tool in a borehole. The acoustic logging tool comprises one or more transmitters and one or more receivers. The method may further comprise taking one or more acquisitions with the acoustic logging tool as the acoustic logging tool traverses through the borehole, creating an azimuth rotation angle array of one or more angles, from the one or more acquisitions, and applying a trial angle selected from the one or more angles of the azimuth rotation angle array to calculate a fast shear waveform.

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: A method and system for downhole measurements of reservoir temperature and pressure and reservoir fluid compressibility, density, viscosity, and bubble point pressure to obtain an oil formation volume factor (FVF) or a gas to oil ratio (GOR) in real time are disclosed. In embodiments, methods include conveying a downhole formation analysis tool into a wellbore, measuring reservoir fluid compressibility, density, viscosity, and bubble point pressure, and obtaining the oil formation volume factor (FVF) or the gas to oil ratio (GOR) while the fluid sampling tool is still in the wellbore.

Abstract: A microsampling device for taking fluid samples in a wellbore. The microsampling device may comprise a microsampling tube in which one or more microsamplers disposed in the microsampling tube. Additionally, the microsampling device may comprise a fluid flow line connected to the microsampling tube in which a fluid sample traverses and a secondary fluid flow line in which at least a part of the fluid sample may traverse from the microsampling tube through the secondary fluid flow line and into a wellbore.

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: Disclosed herein are methods and systems for fluid analysis and, more particularly, for identifying and measuring the concentration of H2S in real-time downhole during the fluid analysis. The methods may include conveying a fluid sampling tool into a wellbore, drawing a formation fluid from a sampling zone, and passing the fluid sample over a H2S gas diffusion barrier that controls H2S diffusion from the fluid sample to a thin film deposited on a measurement region, wherein the measurement region is part of the at least one passageway, and analyzing the fluid sample in the fluid sampling tool for a target analyte.

Abstract: A fluid sampling tool may include a fluid characterization device consisting of a densitometer, a viscometer, or a vibrating element, or a combination thereof and a polymer disposed in or around the fluid characterization device, wherein the polymer volume, density, or viscosity changes with an ionic stimulus. The fluid characterization device may be located within a bypass flow line of the sampling tool. A method of measuring pH and a method of monitoring at least two analytes at the same time using the fluid characterization devices are also discussed.

Abstract: In general, in one aspect, embodiments relate to a method, that includes lowering a downhole tool to a target depth of a wellbore, sampling reservoir fluid containing asphaltene at the target depth using the downhole tool, controlling a pressure of the sampled reservoir fluid while downhole to induce one or more phase transitions of the asphaltene, measuring the sampled reservoir fluid after inducing the one or more phase transitions, and identifying fluid composition of the reservoir fluid based on the measuring.