Formation testing planning and monitoring

• US 9,309,731 B2
• Filed: 10/05/2010
• Issued: 04/12/2016
• Est. Priority Date: 10/06/2009
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Bedouet, Sylvain, Pop, Julian
• Primary Examiner(s): Huynh, Phuong
• Application Number:
  US13/500,459
• Publication Number:
  US 20120316788A1
• Time in Patent Office: 2,016 Days
• US Class Current: 1/1
• CPC Class Codes: E21B 33/124 Units with longitudinally-spaced plugs for isolating the intermediate space
• CPC Class Codes: E21B 47/06 Measuring temperature or pressure
• CPC Class Codes: E21B 47/07 Temperature
• CPC Class Codes: E21B 47/12 Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
• CPC Class Codes: E21B 49/003 by analysing drilling variables or conditions E21B49/005 takes precedence; systems specially adapted for monitoring a plurality of drilling variables or conditions E21B44/00
• CPC Class Codes: E21B 49/008 by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor measuring pressure E21B47/06
• CPC Class Codes: E21B 49/086 Withdrawing samples at the surface

Abstract

An example method comprises collecting formation temperature data along a wellbore extending into a subterranean formation, determining test operating parameter values, performing a wellbore hydraulic simulation of the response of wellbore fluid conditions to the test operating parameter values and the formation temperature data, determining whether the response of wellbore fluid conditions is indicative of one of a well control and a well stability problem, and initiating a test based on the determination whether the response of wellbore fluid conditions is indicative of one of a well control and a well stability problem.

Claims

1. A method comprising:

collecting formation temperature data along a wellbore extending into a subterranean formation using a downhole tool;

performing a wellbore hydraulic simulation, using a processor, of a response of wellbore fluid conditions to initial test operating parameter values and the formation temperature data;

determining, using the processor, whether the response of wellbore fluid conditions is indicative of a well control or stability problem at least partly by;

retrieving into the processor formation pressure data acquired by the downhole tool or by another downhole tool;

determining, using the processor, a wellbore pressure profile from the simulation; and

comparing, using the processor, at least a portion of the formation pressure data with at least a portion of the wellbore pressure profile to identify whether the response of wellbore fluid conditions is indicative of a well control or stability problem; and

initiating a test based on the determination of whether the response of wellbore fluid conditions is indicative of a well control or stability problem.

2. The method of claim 1, wherein at least one of the test operating parameters comprises mud composition, mud type, drawdown duration, or drawdown volume, or any combination thereof.

3. The method of claim 1, comprising determining a test operating configuration, wherein the wellbore hydraulic simulation is performed using the test operating configuration.

4. The method of claim 3, wherein the test operating configuration comprises at least one of:

a packer spatial arrangement of a downhole testing configuration; and

a number of packers of the downhole testing configuration.

5. The method of claim 1, comprising adjusting at least one of the test operating parameter values based on the determination of whether the wellbore pressure profile is indicative of a well control or stability problem.

6. The method of claim 5, comprising repeating the performing step after the adjusting step.

7. The method of claim 1, comprising predicting a well response related to at least one test operating parameter value from the simulation.

8. The method of claim 7, wherein the predicted well response comprises one or more of wellbore pressures at selected locations, wellbore temperature at selected locations, pit gains, or gas elution rate, or any combination thereof.

9. An apparatus, comprising:

means for collecting formation temperature data along a wellbore extending into a subterranean formation;

means for determining test operating parameter values;

means for performing a wellbore hydraulic simulation of a response of wellbore fluid conditions to the test operating parameter values and the formation temperature data;

means for determining whether the response of wellbore fluid conditions is indicative of a well control or stability problem; and

means for initiating a test based on the determination of whether the response of wellbore fluid conditions is indicative of a well control or stability problem.

10. The apparatus of claim 9, wherein at least one of the test operating parameters comprises mud composition, mud type, drawdown duration, or drawdown volume, or any combination thereof.

11. The apparatus of claim 9, wherein the wellbore hydraulic simulation is performed based on an initial test operating configuration, wherein the initial test operating configuration comprises a packer spatial arrangement of a downhole testing configuration or a number of packers of the downhole testing configuration, or a combination thereof.

12. The apparatus of claim 9, wherein the means for determining whether the response of wellbore fluid conditions is indicative of a well control or stability problem comprise:

means for obtaining formation pressure data;

means for determining a wellbore pressure profile from the simulation; and

means for comparing at least a portion of the formation pressure data with at least a portion of the wellbore pressure profile to identify whether the response of wellbore fluid conditions is indicative of a well control or stability problem.

13. The apparatus of claim 9, comprising means for adjusting at least one of the test operating parameter values based on the determination of whether the wellbore pressure profile is indicative of a well control or stability problem.

14. The apparatus of claim 9, comprising means for predicting a well response related to at least one test operating parameter value from the simulation, wherein the predicted well response comprises wellbore pressures at multiple locations, wellbore temperature at multiple locations, pit gains, or gas elution rate, or any combination thereof.

15. One or more tangible, non-transitory machine-readable media comprising instructions executable by a processor to:

retrieve, into the processor, formation temperature data along a wellbore extending into a subterranean formation collected using a first downhole tool;

perform, using the processor, a wellbore hydraulic simulation of a response of wellbore fluid conditions to initial test operating parameter values and the formation temperature data;

determine, using the processor, whether the response of wellbore fluid conditions is indicative of a well control or stability problem at least in part by;

obtaining formation pressure data;

determining a wellbore pressure profile from the simulation; and

comparing at least a portion of the formation pressure data with at least a portion of the wellbore pressure profile to identify whether the response of wellbore fluid conditions is indicative of a well control or stability problem; and

indicate whether the response of wellbore fluid conditions is indicative of the well control or stability problem.

16. The one or more media of claim 15, wherein at least one of the test operating parameters comprises mud composition, mud type, drawdown duration, or drawdown volume, or any combination thereof.

17. The one or more media of claim 15, wherein the instructions to perform the wellbore hydraulic simulation cause the wellbore hydraulic simulation to be performed based on an initial test operating configuration, wherein the initial test operating configuration comprises a packer spatial arrangement of a downhole testing configuration or a number of packers of the downhole testing configuration, or a combination thereof.

18. The one or more media of claim 15, comprising instructions to adjust at least one of the test operating parameter values based on the determination of whether the wellbore pressure profile is indicative of a well control or stability problem.

19. The one or more media of claim 18, comprising instructions to repeat the performance instructions after the adjusting instructions.

20. The one or more media of claim 15, comprising instructions to predict a well response related to at least one test operating parameter value from the simulation, wherein the predicted well response comprises wellbore pressures at multiple locations, wellbore temperature at multiple locations, pit gains, or gas elution rate, or any combination thereof.