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: 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 A fluid can be continuously withdrawn from the formation over a time interval through at least one of the plurality of probes.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 A changing concentration of the tracer solution that is withdrawn from the formation over the time interval can be measured based on the volume of the tracer solution that is withdrawn from the formation over the time interval.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 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: 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: Some implementations include a method for identifying movement of a plug in a borehole of a well. The method may include obtaining, via one or more pressure sensors, pressure data indicating pressures in the borehole during stages of hydraulic fracturing; obtaining well data indicating one or more well geometries and treatment data indicating one or more treatments for hydraulic fracturing; extracting, via a plug movement detector, pressure-related features from the drilling data, well-related features from the well data, and treatment-related features from the treatment data; and outputting, by the plug movement detector, an indication whether the plug moved in the borehole based on the pressure-related features, well-related features, and treatment-related features.

Abstract: Some implementations include a method for identifying movement of a plug in a borehole of a well. The method may include obtaining, via one or more pressure sensors, pressure data indicating pressures in the borehole during stages of hydraulic fracturing; obtaining well data indicating one or more well geometries and treatment data indicating one or more treatments for hydraulic fracturing; extracting, via a plug movement detector, pressure-related features from the drilling data, well-related features from the well data, and treatment-related features from the treatment data; and outputting, by the plug movement detector, an indication whether the plug moved in the borehole based on the pressure-related features, well-related features, and treatment-related features.

Abstract: A method and system for evaluating one or more properties of a wellbore. The method may include generating a tube wave in a piping disposed in a wellbore, creating a time-domain forward model with one or more parameters to represent the tube wave in the piping, and transforming the time-domain forward model to model the tube wave as a pressure wave. The method may further include evaluating a loss function of the time-domain forward model and identifying a second set of parameters from the loss function to adjust the one or more parameters.

Abstract: A method and system for removing a filter cover. A system and method may comprise a downhole fluid sampling tool including 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. In examples, 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: 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: 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: 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: Systems and techniques are described for modeling borehole fluid flow using a dynamic pressure boundary. An example method can include calculating a radius of fluids and a radius of pressure associated with a borehole, the radius of pressure relating to a fluid flow; generating a first model, wherein a size of the first model is larger than the calculated radius of pressure; determining a dynamic pressure based on the first model; generating a second model, wherein a size of the second model is larger than the calculated radius of fluids; and modelling the borehole fluid flow based on the second model, wherein the dynamic pressure is used as a boundary condition of the second model.

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: 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.

Abstract: A method and system for identifying a fluid sample. The method may comprise disposing a fluid sampling tool into a wellbore. The fluid sampling tool may comprise at least one probe configured to fluidly connect the fluid sampling tool to a formation in the wellbore and at least one passageway that passes through the at least one probe and into the fluid sampling tool. The method may further comprise drawing a wellbore fluid as a fluid sample through the at least one probe and through the at least one passageway, obtaining a fluid measurement of the fluid sample, comparing the fluid measurement to a plurality of fingerprints that populate a database, and identifying the fluid sample based at least in part on one of the plurality of fingerprints.

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.

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.