Downhole real-time 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.
1. A method, comprising:
identifying linearly behaving data within obtained data associated with fluid obtained from a subterranean formation;
determining a shrinkage factor based on the linearly behaving data;
determining a function that relates gas-oil ratio (GOR) data of the obtained fluid with the determined shrinkage factor, wherein the function comprises:
ƒ=[GOR 0 −(GOR 0 −GOR)b], where GOR 0 is GOR of the native formation fluid within the obtained fluid, GOR is GOR of the obtained fluid, and b is the determined shrinkage factor; or
g=(GOR 0 −GOR)b, where GOR 0 is GOR of the native formation fluid within the obtained fluid, GOR is GOR of the obtained fluid, and b is the determined shrinkage factor;
determining a first linear relationship between optical density (OD) data of the obtained fluid and the function;
determining a second linear relationship between density data of the obtained fluid and the function;
determining an oil-based mud (OBM) filtrate contamination property of OBM filtrate within the obtained fluid based on the first linear relationship;
determining a native formation property of native formation fluid within the obtained fluid based on the second linear relationship;
estimating a volume fraction of OBM filtrate contamination within the obtained fluid based on the OBM filtrate contamination property and the native formation property; and
operating a downhole sampling tool based on the estimated volume fraction of OBM filtrate contamination within the obtained fluid;
wherein obtaining the obtained data via operation of the downhole sampling tool disposed proximate the subterranean formation in a wellbore extending from a wellsite surface into the subterranean formation, wherein the obtained data is obtained via operation of the downhole sampling tool, or surface equipment disposed at the wellsite surface in communication with the downhole sampling tool, or both.
2. The method of claim 1 wherein the function comprises a first function and the method comprises:
determining a second function that relates GOR data of the obtained fluid with the determined shrinkage factor;
determining the first linear relationship between OD data of the obtained fluid and one of the first and second functions; and
determining the second linear relationship between density data of the obtained fluid and one of the first and second functions.
3. The method of claim 1 wherein determining shrinkage factor based on the linearly behaving data comprises:
determining formation volume factor (FVF) based on the linearly behaving data; and
determining shrinkage factor based on the determined FVF.
4. The method of claim 3 comprising determining molecular weight of gas within the obtained fluid based on the linearly behaving data, wherein determining the FVF is further based on the determined molecular weight of the gas.
5. The method of claim 3 comprising determining a stock tank oil (STO) basis density of the obtained fluid at standard conditions based on the linearly behaving data, wherein determining the FVF is further based on the determined STO-basis density.
6. The method of claim 3 comprising estimating GOR of the native formation fluid based on the linearly behaving data, wherein determining the FVF is further based on the estimated GOR.
7. The method of claim 1 comprising converting the estimated volume fraction of the OBM filtrate contamination to an estimated weight fraction of the OBM filtrate contamination.
8. The method of claim 1 comprising determining a composition of the native formation fluid based on the estimated volume fraction of the OBM filtrate contamination.
9. The method of claim 1 comprising converting the estimated volume fraction of the OBM filtrate contamination from flowline conditions to formation conditions.
10. The method of claim 1 wherein the estimated volume fraction of the OBM filtrate contamination within the obtained fluid is a first estimated volume fraction, and wherein the method comprises:
power law fitting the density data to the GOR data;
determining a second estimated volume fraction of the OBM filtrate contamination within the obtained fluid based on the power law fitting;
determining uncertainty associated with each of the first and second estimated volume fractions; and
either averaging or selecting one of the first and second estimated volume fractions based on the determined uncertainty.