Contamination prediction of downhole pumpout and sampling
A method may comprise positioning a downhole fluid sampling tool into a wellbore, performing a pressure test operation within the wellbore, performing a pumpout operation within the wellbore, identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation, and acquiring the clean fluid sample from the wellbore. A system may comprise a downhole fluid sampling tool and an information handling machine. The downhole fluid sampling tool may further comprise one or more probes attached to the downhole fluid sampling tool, one or more stabilizers attached to the downhole fluid sampling tool, and a sensor placed in the downhole fluid sampling tool configured to measure drilling fluid filtrate.
1. A method comprising:
positioning a downhole fluid sampling tool into a wellbore;
performing a pressure test operation within the wellbore;
performing a pumpout operation within the wellbore;
identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation;
acquiring the clean fluid sample from the wellbore; and
predicting contamination levels of a formation fluid from a correlation model using one or more formation properties and pumpout data.
2. The method of claim 1 , further comprising compiling a dataset of one or more formation properties from the pressure test operation.
3. The method of claim 2 , wherein the one or more formation properties include at least one of formation pressure, wellbore pressure, drawdown mobility, drawdown pressure, bleed off pressure, pumpout volume, fluid density, or fluid viscosity.
4. The method of claim 1 , further comprising measuring a contamination level of a fluid sample as a function of pumpout volume.
5. The method of claim 1 , further comprising parameterizing a pumpout trend of a formation fluid from the pumpout operation.
6. The method of claim 1 , wherein the identifying when the clean fluid sample may be taken includes a mapping scheme or machine learning.
7. The method of claim 1 , further comprising developing a correlation between a pumpout trend model, one or more formation properties, mud cake properties, and formation fluid properties to determine contamination of a formation fluid.
8. A method of claim 1 , further comprising performing the pressure test and pumpout operation in real time.
9. The method of claim 1 , wherein the clean fluid sample is below 5% contamination for an oil, below 2% contamination for a volatile oil, or less than 1% for a condensate.
10. The method of claim 1 , wherein the downhole tool comprises:
one or more probes;
one or more stabilizers; and
a sensor configured to measure drilling fluid filtrate.
11. A method comprising:
positioning a downhole fluid sampling tool into a wellbore, wherein the downhole tool comprises;
one or more probes;
one or more stabilizers; and
a sensor configured to measure drilling fluid filtrate;
performing a pressure test operation within the wellbore;
performing a pumpout operation within the wellbore;
identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation;
acquiring the clean fluid sample from the wellbore;
compiling a dataset of one or more formation properties from the pressure test operation wherein the one or more formation properties include at least one of formation pressure, wellbore pressure, drawdown mobility, drawdown pressure, bleed off pressure, pumpout volume, fluid density, or fluid viscosity;
parameterizing a pumpout trend of a formation fluid from the pumpout operation; and
predicting contamination levels of a formation fluid from a correlation model using one or more formation properties and pumpout data.
12. The method of claim 11 , further comprising measuring a contamination level of a fluid sample as a function of pumpout volume.
13. The method of claim 11 , wherein the identifying when the clean fluid sample may be taken includes a mapping scheme.
14. The method of claim 11 , wherein the identifying when the clean fluid sample may be taken includes machine learning.
15. The method of claim 14 , wherein the machine learning de-spikes the dataset.
16. The method of claim 11 , further comprising developing a correlation between a pumpout trend model, one or more formation properties, mud cake properties, and formation fluid properties to determine contamination of a formation fluid.
17. The method of claim 11 , further comprising performing the pressure test and pumpout operation in real time.
18. The method of claim 11 , wherein the clean fluid sample is below 5% contamination for an oil, below 2% contamination for a volatile oil, or less than 1% for a condensate.
19. A method comprising:
positioning a downhole fluid sampling tool into a wellbore;
performing a pressure test operation within the wellbore;
performing a pumpout operation within the wellbore;
identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation;
acquiring the clean fluid sample from the wellbore; and
developing a correlation between a pumpout trend model, one or more formation properties, mud cake properties, and formation fluid properties to determine contamination of a formation fluid.
20. A method comprising:
positioning a downhole fluid sampling tool into a wellbore, wherein the downhole tool comprises;
one or more probes;
one or more stabilizers; and
a sensor configured to measure drilling fluid filtrate;
performing a pressure test operation within the wellbore;
performing a pumpout operation within the wellbore;
identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation wherein the identifying when the clean fluid sample may be taken includes machine learning;
acquiring the clean fluid sample from the wellbore;
compiling a dataset of one or more formation properties from the pressure test operation wherein the one or more formation properties include at least one of formation pressure, wellbore pressure, drawdown mobility, drawdown pressure, bleed off pressure, pumpout volume, fluid density, or fluid viscosity; and
parameterizing a pumpout trend of a formation fluid from the pumpout operation.
21. A method comprising:
positioning a downhole fluid sampling tool into a wellbore, wherein the downhole tool comprises;
one or more probes;
one or more stabilizers; and
a sensor configured to measure drilling fluid filtrate;
performing a pressure test operation within the wellbore;
performing a pumpout operation within the wellbore;
identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation wherein the identifying when the clean fluid sample may be taken includes machine learning which de-spikes the dataset;
acquiring the clean fluid sample from the wellbore;
compiling a dataset of one or more formation properties from the pressure test operation wherein the one or more formation properties include at least one of formation pressure, wellbore pressure, drawdown mobility, drawdown pressure, bleed off pressure, pumpout volume, fluid density, or fluid viscosity; and
parameterizing a pumpout trend of a formation fluid from the pumpout operation.
22. A method comprising:
positioning a downhole fluid sampling tool into a wellbore, wherein the downhole tool comprises;
one or more probes;
one or more stabilizers; and
a sensor configured to measure drilling fluid filtrate;
performing a pressure test operation within the wellbore;
performing a pumpout operation within the wellbore;
identifying when a clean fluid sample may be taken by the downhole fluid sampling tool from at least the pressure test operation and the pumpout operation;
acquiring the clean fluid sample from the wellbore;
compiling a dataset of one or more formation properties from the pressure test operation wherein the one or more formation properties include at least one of formation pressure, wellbore pressure, drawdown mobility, drawdown pressure, bleed off pressure, pumpout volume, fluid density, or fluid viscosity;
parameterizing a pumpout trend of a formation fluid from the pumpout operation; and
developing a correlation between a pumpout trend model, one or more formation properties, mud cake properties, and formation fluid properties to determine contamination of a formation fluid.