Schlumberger Technology Corporation

Ryan Sangjun Lee

Youxiang Zuo

Adriaan Gisolf

Kang Wang

Oliver Clinton Mullins

Cosan Ayan

Sylvain Bedouet

Ashers Partouche

Yong Chang

Shu Pan

Kai Hsu

Lei Jiang

Peter S Hegeman

Nikita Chugunov

Hadrien Dumont

Beatriz E Barbosa

XiaoWei Sheng

Chetankumar Natwarlal Desai

Morten Kristensen

Sai Venkatakrishnan

Suchart Chokthanyawat

Lixiang Sun

Jonathan Leonard

Disclosed are methods and apparatus pertaining to processing in-situ, real-time data associated with fluid obtained by a downhole sampling tool. The processing includes generating a population of values for &#x108;, where each value of &#x108; is an estimated value of a fluid property for native formation fluid within the obtained fluid. The obtained data is iteratively fit to a predetermined model in linear space. The model relates the fluid property to pumpout volume or time. Each iterative fitting utilizes a different one of the values for &#x108;. A value &#x108;* is identified as the one of the values &#x108; that minimizes model fit error in linear space based on the iterative fitting. Selected values &#x108; that are near &#x108;* are then assessed to determine which one has a minimum integral error of nonlinearity in logarithmic space.

Estimating contamination during focused sampling

Implementations of the present disclosure relate to apparatuses, systems, and methods for determining when a well cleanup process has established developed flow and then extrapolating out modeled fluid parameter values to determine parameter values for a formation fluid. The model fluid parameter values may be modeled using a power law function having a specified exponent value.

Flow regime identification with filtrate contamination monitoring

A method includes identifying linearly behaving data within obtained data associated with fluid obtained from a subterranean formation. Shrinkage factor is determined based on the linearly behaving data. A function relating GOR data of the obtained fluid with the determined shrinkage factor is determined. A first linear relationship between optical density (OD) data of the obtained fluid and the function is determined. A second linear relationship between density data of the obtained fluid and the function is determined. An oil-based mud (OBM) filtrate contamination property of OBM filtrate within the obtained fluid based on the first linear relationship is determined. A native formation property of native formation fluid within the obtained fluid based on the second linear relationship is determined. A volume fraction of OBM filtrate contamination within the obtained fluid based on the OBM filtrate contamination property and the native formation property is estimated.

Downhole real-time filtrate contamination monitoring

A configuration for testing fluid with a single packer includes at least one sample inlet and at least one guard inlet surrounding a periphery of the at least one sample inlet, wherein the at least one sample inlet has at least one side that is parallel to another side of the at least one sample inlet and the at least one sample inlet has at least two rounded ends connecting each of the parallel sides, and the at least one guard inlet has at least one side that is parallel to another side of the at least one guard inlet and the at least one guard inlet has at least two rounded ends connecting each of the parallel side of the guard inlet.

Single packer inlet configurations

A method includes operating a downhole acquisition tool in a wellbore in a geological formation. The wellbore or the geological formation, or both, contains first fluid that includes a native reservoir fluid of the geological formation and a contaminant. The method also includes receiving a portion of the first fluid into the downhole acquisition tool and determining a plurality of properties of the portion of the first fluid using the downhole acquisition tool. The plurality of properties includes a mass fraction of a component of the portion of the first fluid and a density of the portion of the first fluid. The method also includes using the processor to estimate a volume fraction of the contaminant in the portion of the first fluid based at least in part on a composition mass fraction function that depends at least on the mass fraction of the component in the portion of the first fluid and the density of the portion of the first fluid.

Downhole filtrate contamination monitoring

A method includes operating a downhole acquisition tool in a wellbore in a geological formation. The wellbore or the geological formation, or both contains a fluid that includes a native reservoir fluid of the geological formation and a contaminant. The method also includes receiving a portion of the fluid into the downhole acquisition tool, measuring a fluid property of the portion of the fluid using the downhole acquisition tool, and using the processor to estimate a fluid property of the native reservoir fluid based on the measured fluid property of the portion of the fluid and a regression model that may predict an asymptote of a growth curve. The asymptote corresponds to the estimated fluid property of the native formation fluid, and the regression model includes a geometric fitting model other than a power-law model.

Disclosed are methods and apparatus pertaining to processing in-situ, real-time data associated with fluid obtained by a downhole sampling tool. The processing includes generating a population of values for &#x108;, where each value of &#x108; is an estimated value of a fluid property for native formation fluid within the obtained fluid. The obtained data is iteratively fit to a predetermined model in linear space. The model relates the fluid property to pumpout volume or time. Each iterative fitting utilizes a different one of the values for &#x108;. A value &#x108;* is identified as the one of the values for &#x108; that minimizes model fit error in linear space based on the iterative fitting. Selected values for &#x108; that are near &#x108;* are then assessed to determine which one has a minimum integral error of nonlinearity in logarithmic space.

A downhole tool operable to pump a volume of contaminated fluid from a subterranean formation during an elapsed pumping time while obtaining in-situ, real-time data associated with the contaminated fluid. The contaminated fluid includes native formation fluid and oil-based mud (OBM) filtrate. A shrinkage factor of the contaminated fluid is determined based on the in-situ, real-time data. The contaminated fluid shrinkage factor is fit relative to pumped volume or pumping time to obtain a function relating the shrinkage factor with pumped volume or elapsed pumping time. A shrinkage factor of the native formation fluid is determined based on the function. A shrinkage factor of the OBM filtrate is also determined. OBM filtrate volume percentage is determined based on the shrinkage factor of the native formation fluid and the shrinkage factor of the OBM filtrate.

Applying shrinkage factor to real-time OBM filtrate contamination monitoring

Methods and systems for generating and utilizing a proxy model that generates a pumping parameter as a function of contamination. The pumping parameter is descriptive of a pumpout time or volume of fluid to be obtained from a formation by a downhole sampling tool positioned in a wellbore extending into the formation. The contamination is a percentage of the fluid obtained by the downhole sampling tool that is not native to the formation. The proxy model is based on a true model that utilizes true model input parameters that include the pumping parameter, formation parameters descriptive of the formation, and a filtrate parameter descriptive of a drilling fluid utilized to form the wellbore. The output of the true model is the contamination as a function of the pumping parameter. The proxy model utilizes proxy model input parameters each related to one or more of the true model input parameters.

Cleanup model parameterization, approximation, and sensitivity

A method for performing contamination monitoring through estimation wherein measured data for optical density, gas to oil ratio, mass density and composition of fluid components are used to obtain plotting data and the plotting data is extrapolated to obtain contamination levels.

Method and apparatus for consistent and robust fitting in oil based mud filtrate contamination monitoring from multiple downhole sensors

Disclosed are methods and apparatus obtaining in-situ, real-time data associated with a sample stream obtained by a downhole sampling apparatus disposed in a borehole that extends into a subterranean formation. The obtained data includes multiple fluid properties of the sample stream. The sample stream includes native formation fluid from the subterranean formation and filtrate contamination resulting from formation of the borehole in the subterranean formation. The obtained data is filtered to remove outliers. The filtered data is fit to each of a plurality of models each characterizing a corresponding one of the fluid properties as a function of a pumpout volume or time of the sample stream. Based on the fitted data, a start of a developed flow regime of the native formation fluid within the subterranean formation surrounding the borehole is identified.

Data extraction for OBM contamination monitoring

A method includes operating a downhole acquisition tool including a guard probe and a sample probe in a wellbore that contains a fluid that includes a native reservoir fluid and a contaminant. The method also includes receiving a first portion of fluid into the guard probe and a second portion of fluid into the sample probe, estimating a contamination level of the first or second portions based on a fluid property of the respective first and second portions, determining an initial guard flow rate of the first portion, determining an initial sample flow rate of the second portion, using a processor to adjust a guard flow rate of the second portion over pump time after the contamination level of the first portion is at or below a contamination level threshold, and adjust a sample flow rate of the first portion based on the adjusted guard flow rate and total flowrate.

Systems and methods for controlling flow rate in a focused downhole acquisition tool

Single packers inlet configurations

A tool is to be used within a wellbore including a wall and extending into a formation with formation fluid. The tool includes a packer expandable against the wellbore wall with ports included within the packer to enable formation fluid to flow into the tool from the formation. The ports are arranged in a first port configuration optimized based upon a first predetermined formation property.

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Sugar Land, TX, United States of America

Ryan Sangjun Lee