Ryan O Lee

20190264560, Aug 29, 2019

May 14, 2019

16/411845

- Sugar Land TX, US
Kang Wang - Houston TX, US
Adriaan Gisolf - Bucharest, RO
Ryan Sangjun Lee - Sugar Land TX, US
Oliver C. Mullins - Houston TX, US
Shu Pan - Sugar Land TX, US

E21B 49/08
G01N 33/28

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.

20170152743, Jun 1, 2017

Dec 1, 2015

14/956338

- Sugar Land TX, US
Kai Hsu - Sugar Land TX, US
Yong Chang - Sugar Land TX, US
Youxiang Zuo - Burnaby, CA
Ryan Sangjun Lee - Sugar Land TX, US
Ashers Partouche - Katy TX, US

E21B 49/08
G01N 1/14
E21B 49/10

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.

20160319662, Nov 3, 2016

Apr 21, 2016

15/135411

- Sugar Land TX, US
Kang Wang - Beijing, CN
Adriaan Gisolf - Houston TX, US
Ryan Sangjun Lee - Sugar Land TX, US

E21B 49/08
G01F 22/00

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.

20160216404, Jul 28, 2016

Jan 25, 2016

15/005531

- Sugar Land TX, US
Cosan Ayan - Istanbul, TR
Ryan Sangjun Lee - Sugar Land TX, US
Nikita Chugunov - Arlington MA, US

G01V 99/00
G06F 17/10

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.

20160186559, Jun 30, 2016

Dec 18, 2015

14/975700

- Sugar Land TX, US
Ryan Sangjun Lee - Sugar Land TX, US
Youxiang Zuo - Burnaby, CA
Sai Venkatakrishnan - Beijing, CN
XiaoWei Sheng - Beijing, CN
Suchart Chokthanyawat - Bangkok, TH
Lei Jiang - Beijing, CN
Lixiang Sun - Katy TX, US

E21B 49/08

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.

20160186560, Jun 30, 2016

Dec 18, 2015

14/975704

- Sugar Land TX, US
Adriaan Gisolf - Houston TX, US
Kang Wang - Beijing, CN
Ryan Sangjun Lee - Sugar Land TX, US

E21B 49/08
E21B 47/00

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.

20160090836, Mar 31, 2016

Sep 28, 2015

14/867262

- Sugar Land TX, US
Youxiang Zuo - Burnaby, CA
Ryan Sangjun Lee - Sugar Land TX, US
Adriaan Gisolf - Houston TX, US

E21B 49/08

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.

20150308264, Oct 29, 2015

Apr 27, 2015

14/697382

- Sugar Land TX, US
Kang Wang - Beijing, CN
Adriaan Gisolf - Sugar Land TX, US
Ryan Sangjun Lee - Sugar Land TX, US
Oliver C. Mullins - Houston TX, US
Shu Pan - Edmonton, CA

E21B 49/08
G01N 33/28

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.