Halliburton Energy Services, Inc.

Waqar Ahmad Khan

Christopher Michael Jones

Mehdi Alipour Kallehbasti

Songhua Chen

Lilong Li

Mehdi Azari

Sami Abbas Eyuboglu

Syed Muhammad Farrukh Hamza

Abbas Sami Eyuboglu

Abdolhamid Hadibeik

Sandeep Ramakrishna

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.

Contamination estimation of formation samples

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.

Quantifying contamination of downhole samples

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.

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.

Acquiring formation fluid samples using micro-fracturing

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.

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Houston, TX, United States of America

Waqar Ahmad Khan