Abstract: Methods for determining a compressibility factor are disclosed. A method may include disposing a downhole fluid analysis tool within a wellbore, extracting a formation fluid from the wellbore, pumping the formation fluid through the downhole fluid analysis tool, measuring at least one of a flowline temperature, a flowline pressure, a formation fluid mass density, and a pumped volume, measuring compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) in the formation fluid, estimating pluralities of molecular weight of C6+ in the formation fluid, estimating pluralities of molecular weight of the formation fluid, calculating the compressibility factor of the formation fluid based upon the flowline temperature, the flowline pressure, the formation fluid mass density, and the molecular weight of the formation fluid, and outputting the compressibility factor of the formation fluid.

Abstract: Systems and methods for electromagnetic (EM)-assisted in-situ biomining are provided. A method for in-situ mining in a rock formation in an area of interest includes: receiving a first micro-organism from a micro-organism source at a first well extending downward from a ground surface in the area of interest, injecting the first micro-organism into a permeable layer of the rock formation via the first well to dissolve a target material to form a solution containing the first micro-organism and the target material, applying an electric field to the first micro-organism by the first well operating as a first electrode and a second well operating as a second electrode, such that the electric field stimulates activity of the first micro-organism, receiving the solution via the second well, and pumping the solution, via the second well, to a processing plant to separate the target material from the first micro-organism.

Abstract: A method includes receiving first fluid property data from a sample flowline of a focused sampling system and receiving second fluid property data from a guard flowline of the focused sampling system.

Abstract: The disclosed techniques relate to techniques for determining a CO2 concentration based on a ratio of one or more peaks in carbon dioxide (CO2) optical spectrometer measurement data. For example, the techniques include receiving CO2 measurement data corresponding to a region within a geological formation; identifying a peak corresponding to CO2 based on the CO2 measurement data; determining a ratio between the peak and a hydrocarbon reference measurement; selecting a model for determining a CO2 concentration based on the ratio; determining the CO2 concentration using the selected model; and generating a downhole operation output based on the determined CO2 concentration.

Abstract: A method includes positioning a downhole acquisition tool in a wellbore in a geological formation. The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore. Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module.

Abstract: A method for cement evaluation through dual-string pipes comprising the steps of: i) acquiring waveforms data using a cement bond logging tool; ii) processing the acquired waveforms data to eliminate one or more potential DC offsets; iii) selecting a first receiver to further process the processed acquired waveforms data in a common-receiver domain; iv) performing in-situ calibration using the processed acquired waveforms data from the common-receiver domain to identify free-pipe and wall-bonded waveforms; v) calculating normalized amplitudes from monopole waveforms and azimuthal waveforms obtained from the free-pipe and wall-bonded waveforms to determine bond index and generate cement map; and vi) calculating statistical averages and variances using the calculated normalized amplitude to generate a final presentation.

Abstract: The disclosed techniques relate to fluid monitoring and classification techniques that include a method that includes acquiring, via a spectral analysis module of a sampling system of a downhole well tool, spectral data for an unknown reservoir fluid received by the sampling system of the downhole well tool from a geological formation; determining, via the one or more processors, a fluid type of the unknown reservoir fluid in the sampling system of the downhole well tool based at least in part on projections of the spectral data for the unknown reservoir fluid onto at least the first two eigenvectors of spectral data of known fluids stored in a spectral database; and generating, via the one or more processors, a downhole well operation decision based on the determined fluid type of the unknown reservoir fluid in substantially real-time while the sampling system of the downhole well tool receives the unknown reservoir fluid.

Abstract: In some embodiments, a process can include obtaining a first formation fluid sample using a sample-line of a focused fluid sampling system and obtaining a second formation fluid sample using a guard-line of the focused fluid sampling system. The process can also include measuring a first optical density spectrum of the first formation fluid sample and measuring a second optical density spectrum of the second formation fluid sample. The process can also include decolorizing the first and second optical density spectrums to produce a decolorized first spectrum and a decolorized second spectrum, respectively. The process can also include normalizing the first and second decolorized spectrums to provide a first normalized spectrum and a second normalized spectrum. The process can also include determining a difference between the first and the second normalized spectrums to provide a sampling difference and adjusting a fluid sampling operation based on the sampling difference.

Abstract: Embodiments present a method for fluid type identification from a downhole fluid analysis that uses machine learning techniques that are trained and derived from a computer model using pressure, temperature and downhole optical characteristics of sampled fluid.

Abstract: A method includes positioning a downhole acquisition tool in a wellbore in a geological formation. The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore. Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module.

Abstract: This disclosure relates to a separating a fluid having multiple phases during formation testing. For example, certain embodiments of the present disclosure relate to receiving contaminated formation fluid on a first flow line and separating a contamination (e.g., mud filtrate) from the formation fluid by diverting the relatively heavier and/or denser fluid (e.g., the mud filtrate) downward through a second flow line and diverting the relatively lighter and/or less dense fluid upward through a third flow line. In some embodiments, the third flow line is generally oriented upwards at a height that may facilitate the separation of the heavier fluid from the relatively lighter fluid based on gravity and/or pumps.

Abstract: A method includes positioning a downhole acquisition tool in a wellbore in a geological formation. The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore. Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module.

Abstract: The disclosure provides for a method for setting an inflatable packer. The method includes positioning an inflatable packer within a borehole, and pumping fluid into an inflatable element of the inflatable packer using a pump that is driven by a motor. The method includes measuring pressure of the inflatable element, determining a derivative of the measured pressure with respect to time, and determining onset of restraining of the inflatable element has occurred. Upon or after determining the onset of restraining, the method includes turning off the motor or slowing down an rpm of the motor. The disclosure also provides for a system, including a computer readable medium with processor-executable instructions stored thereon that are configured to instruct a processor to execute a pressure control algorithm to control a speed of the motor in response to pressure measurement data from the pressure sensor.

Abstract: The disclosure provides for a method for setting an inflatable packer. The method includes positioning an inflatable packer within a borehole, and pumping fluid into an inflatable element of the inflatable packer using a pump that is driven by a motor. The method includes measuring pressure of the inflatable element, determining a derivative of the measured pressure with respect to time, and determining onset of restraining of the inflatable element has occurred. Upon or after determining the onset of restraining, the method includes turning off the motor or slowing down an rpm of the motor. The disclosure also provides for a system, including a computer readable medium with processor-executable instructions stored thereon that are configured to instruct a processor to execute a pressure control algorithm to control a speed of the motor in response to pressure measurement data from the pressure sensor.

Abstract: Embodiments present a method for fluid type identification from a downhole fluid analysis that uses machine learning techniques that are trained and derived from a computer model using pressure, temperature and downhole optical characteristics of sampled fluid. The method comprises collecting optical spectral data for a downhole fluid; providing the collected optical spectral data to a trained classification module; processing the collected optical spectral data with the trained classification module configured to determine a fluid type classification; and determining a fluid type based upon the classification based upon the trained classification module.

Abstract: This disclosure relates to a separating a fluid having multiple phases during formation testing. For example, certain embodiments of the present disclosure relate to receiving contaminated formation fluid on a first flow line and separating a contamination (e.g., mud filtrate) from the formation fluid by diverting the relatively heavier and/or denser fluid (e.g., the mud filtrate) downward through a second flow line and diverting the relatively lighter and/or less dense fluid upward through a third flow line. In some embodiments, the third flow line is generally oriented upwards at a height that may facilitate the separation of the heavier fluid from the relatively lighter fluid based on gravity and/or pumps.

Abstract: The disclosure provides for a method for setting an inflatable packer. The method includes positioning an inflatable packer within a borehole, and pumping fluid into an inflatable element of the inflatable packer using a pump that is driven by a motor. The method includes measuring pressure of the inflatable element, determining a derivative of the measured pressure with respect to time, and determining onset of restraining of the inflatable element has occurred. Upon or after determining the onset of restraining, the method includes turning off the motor or slowing down an rpm of the motor. The disclosure also provides for a system, including a computer readable medium with processor-executable instructions stored thereon that are configured to instruct a processor to execute a pressure control algorithm to control a speed of the motor in response to pressure measurement data from the pressure sensor.

Abstract: Embodiments of the disclosure can include systems and methods for formation fluid sampling. In one embodiment, a method can include monitoring a relationship between a first characteristic of a formation fluid extracted from a formation and a second characteristic of the formation fluid extracted from the formation, determining, based at least in part on the monitoring, that a linear trend is exhibited by the relationship between the first characteristic of the formation fluid extracted from the formation and the second characteristic of the formation fluid extracted from the formation, and determining a reservoir fluid breakthrough based at least in part on the identification of the linear trend, wherein the reservoir fluid breakthrough is indicative of virgin reservoir fluid entering a sampling tool.

Abstract: This disclosure relates to a separating a fluid having multiple phases during formation testing. For example, certain embodiments of the present disclosure relate to receiving contaminated formation fluid on a first flow line and separating a contamination (e.g., mud filtrate) from the formation fluid by diverting the relatively heavier and/or denser fluid (e.g., the mud filtrate) downward through a second flow line and diverting the relatively lighter and/or less dense fluid upward through a third flow line. In some embodiments, the third flow line is generally oriented upwards at a height that may facilitate the separation of the heavier fluid from the relatively lighter fluid based on gravity and/or pumps.

Abstract: A method includes positioning a downhole acquisition tool in a wellbore in a geological formation. The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore. Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module.