Abstract: Contamination estimation of a mud filtrate or reservoir sample requires a robust handle on the properties of mud filtrate at downhole conditions. Coupling acquired data with downhole measured data provides a robust estimation of contamination by encompassing the entire available data. Downhole density of the mud filtrate sample may be estimated based on a characteristic of the mud filtrate sample. A density of a formation fluid of the reservoir may be determined using a formation tester tool. The contamination of the formation fluid may be estimated based on the clean fluid density and the estimated mud filtrate density by, for example, using a material balance equation or ratio. An estimated pump-out time for the formation fluid may be determined based on the estimated contamination and a trend of the estimated contamination of the formation fluid.

Abstract: Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) is selected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determine a fluid property value. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Abstract: Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) is selected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determining a fluid property values. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Abstract: Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) isselected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determining a fluid property values. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Abstract: A system includes a pressure transient analysis test tool with flow analysis components and at least one pressure sensor. The pressure transient analysis test tool collects pressure measurements for at least one target position in a borehole as a function of time and fluid flow rate. The system also includes at least one processor that receives saturation analysis results and porosity analysis results related to each target position. The processor estimates relative permeability values based at least in part on the pressure measurements, the saturation analysis results, and the porosity analysis results.

Abstract: Contamination estimation of a mud filtrate or reservoir sample requires a robust handle on the properties of mud filtrate at downhole conditions. Coupling acquired data with downhole measured data provides a robust estimation of contamination by encompassing the entire available data. Downhole density of the mud filtrate sample may be estimated based on a characteristic of the mud filtrate sample. A density of a formation fluid of the reservoir may be determined using a formation tester tool. The contamination of the formation fluid may be estimated based on the clean fluid density and the estimated mud filtrate density by, for example, using a material balance equation or ratio. An estimated pump-out time for the formation fluid may be determined based on the estimated contamination and a trend of the estimated contamination of the formation fluid.

Abstract: A formation-tester tool may be positioned downhole in an openhole wellbore. The formation-tester tool may suspend proppant in fracturing fluid located in a chamber of the formation-tester tool. The formation-tester tool may generate a test fracture in an uncased wall of an area of interest of a subterranean formation adjacent to the openhole wellbore and inject the fracturing fluid and the proppant toward the uncased wall and into the test fracture. The formation-tester tool may retrieve a fluid sample from a reservoir within the area of interest of the subterranean formation by creating a drawdown pressure in the test fracture.

Abstract: A method and system for downhole, real-time determination of relative permeability with nuclear magnetic resonance and formation testing measurements is provided. The method includes introducing a nuclear magnetic (NMR) tool and a formation testing tool into a well bore penetrating a subterranean formation. The method also includes measuring a saturation of a fluid in the subterranean formation from the NMR tool, measuring a mobility of the fluid from the formation testing tool, and measuring a viscosity of the fluid. The method includes calculating a relative permeability of the subterranean formation based on the measured saturation, the measured viscosity and the measured mobility. The method also includes providing a reservoir production prediction metric based on the calculated relative permeability of the subterranean formation for facilitating a well completion operation in the wellbore.

Abstract: A method and system for downhole, real-time determination of relative permeability with nuclear magnetic resonance and formation testing measurements is provided. The method includes introducing a nuclear magnetic (NMR) tool and a formation testing tool into a well bore penetrating a subterranean formation. The method also includes measuring a saturation of a fluid in the subterranean formation from the NMR tool, measuring a mobility of the fluid from the formation testing tool, and measuring a viscosity of the fluid. The method includes calculating a relative permeability of the subterranean formation based on the measured saturation, the measured viscosity and the measured mobility. The method also includes providing a reservoir production prediction metric based on the calculated relative permeability of the subterranean formation for facilitating a well completion operation in the wellbore.

Abstract: Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) is tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determining a fluid property values. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Abstract: Methods and system to calculate a skin effect using wellbore temperature measurements are described herein. In a generalized method, data corresponding to wellbore characteristics, reservoir characteristics, and a preliminary pressure drop around a wellbore due to a Joule-Thomson (“J-T”) effect are obtained downhole. The data is then input into a wellbore fluid temperature model and/or a reservoir fluid temperature model to calculate a wellbore fluid temperature profile and/or reservoir fluid temperature profile, respectively. The calculated wellbore and/or reservoir fluid temperature profiles may be calibrated using fluid temperatures measurements in the wellbore. The calibration may involve comparing the calculated temperature profiles to the measured temperature profiles to ensure the difference between the two profiles does not exceed an error threshold.

Abstract: A formation-tester tool may be positioned downhole in an openhole wellbore. The formation-tester tool may suspend proppant in fracturing fluid located in a chamber of the formation-tester tool. The formation-tester tool may generate a test fracture in an uncased wall of an area of interest of a subterranean formation adjacent to the openhole wellbore and inject the fracturing fluid and the proppant toward the uncased wall and into the test fracture. The formation-tester tool may retrieve a fluid sample from a reservoir within the area of interest of the subterranean formation by creating a drawdown pressure in the test fracture.

Abstract: Contamination estimation of a mud filtrate or reservoir sample requires a robust handle on the properties of mud filtrate at downhole conditions. Coupling acquired data with downhole measured data provides a robust estimation of contamination by encompassing the entire available data. Downhole density of the mud filtrate sample may be estimated based on a characteristic of the mud filtrate sample. A density of a formation fluid of the reservoir may be determined using a formation tester tool. The contamination of the formation fluid may be estimated based on the clean fluid density and the estimated mud filtrate density by, for example, using a material balance equation or ratio. An estimated pump-out time for the formation fluid may be determined based on the estimated contamination and a trend of the estimated contamination of the formation fluid.