System, Method and Computer-Program Product for In-Situ Calibration of a Wellbore Resistivity Logging Tool

• US 20150241596A1
• Filed: 07/26/2013
• Published: 08/27/2015
• Est. Priority Date: 07/26/2013
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Donderici, Burkay
• Granted Patent: US 10,444,404 B2
• Time in Patent Office: Days
• US Class Current: 1/1
• CPC Class Codes: E21B 7/04 Directional drilling
• CPC Class Codes: G01V 13/00 Manufacturing, calibrating, cleaning, or repairing instruments or devices covered by groups G01V1/00 – G01V11/00
• CPC Class Codes: G01V 3/26 operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device with electromagnetic waves G01V3/30
• CPC Class Codes: G01V 3/28 using induction coils

Abstract

In-situ calibration of a resistivity logging tool is accomplished using a variety of methods in which deep measurement signals are calibrated using acquired and simulated measurement signals.

Claims

1. A method for in-situ calibration of a logging tool deployed along a wellbore, the method comprising:

acquiring a first measurement signal of a formation using the logging tool;

simulating a second measurement signal of the formation;

calculating a calibration coefficient based on a comparison between the acquired first measurement signal and the simulated second measurement signal;

acquiring a third measurement signal of the formation using the logging tool, wherein the first, second and third measurement signals correspond to the same transmitter-receiver pair of the logging tool; and

calibrating the acquired third measurement signal using the calibration coefficient.

2. A method as defined in claim 1, wherein the acquired first measurement signal, simulated second measurement signal, and acquired third measurement signal are all deep measurement signals.

3. A method as defined in claim 1, wherein simulating the second measurement signal further comprises:

acquiring a reference measurement signal of the formation using the logging tool;

calculating layer resistivity data of the formation using the acquired reference measurement signal;

selecting a set of calibration depths along the wellbore; and

simulating the second measurement signal at the selected calibration depths using the layer resistivity data.

4. A method as defined in claim 3, wherein the reference measurement signal is a shallow measurement signal.

5. A method as defined in claim 3, wherein the first measurement signal is acquired at a depth which corresponds to at least one of the selected set of calibration depths.

6. A method as defined in claim 3, wherein:

the reference measurement signal is acquired within a first calibration zone of the formation, the first calibration zone being a first range of wellbore depths;

the first measurement signal is acquired within the first calibration zone;

the second measurement signal is simulated within the first calibration zone; and

the third measurement signal is acquired within an application zone located along a second range of wellbore depths different from the first calibration zone.

7. A method as defined in claim 3, wherein selecting the set of calibration depths further comprises:

generating a log response of a plurality of acquired first measurement signals; and

selecting those calibration depths which correspond to zero slopes along the log response.

8. A method as defined in claim 1, wherein the acquired first measurement signal is a low frequency signal comprising a frequency low enough such that the acquired first measurement signal is not affected by variations in the formation.

9. A method as defined in claim 8, wherein the acquired first and third measurement signals are deep measurement signals.

10. A method as defined in claim 8, wherein the simulated second measurement signal is substantially depth invariant.

11. A method as defined in claim 8, wherein:

the first measurement signal is acquired within a first calibration zone of the formation, the first calibration zone being a first range of wellbore depths;

the second measurement signal is simulated within the first calibration zone; and

the third measurement signal is acquired within an application zone located along a second range of wellbore depths different from the first calibration zone.

12. A method as defined in claim 6 or 11, further comprising:

acquiring a fourth measurement signal within a second calibration zone of the formation, the second calibration zone being a third range of wellbore depths different from the first calibration zone; and

calibrating the acquired fourth measurement signal.

13. A method as defined in claim 1, wherein calculating the calibration coefficient further comprises utilizing a calibration model to calculate a plurality of calibration coefficients along a calibration zone of the formation, the calibration zone being a first range of wellbore depths, wherein the third measurement signal is acquired and calibrated within an application zone located along a second range of wellbore depths different from the calibration zone.

14. A method as defined in claim 1, wherein calculating the calibration coefficient further comprises utilizing a calibration model to calculate a plurality of calibration coefficients along a calibration zone of the formation, the calibration zone being a first range of wellbore depths, wherein the third measurement signal is acquired and calibrated within the calibration zone.

15. A method as defined claim 13 or 14, wherein the calibration model is a polynomial function.

16. A method as defined in claim 15, wherein the calibration model is F(X)=AX, where A is a calibration coefficient.

17. A method as defined in claim 15, wherein the calibration model is F(X)=AX+B, where A and B are the calibration coefficients.

18. A method as defined in claim 13 or 14, wherein the calibration coefficients are calculated at depths that satisfy a criterion based on a rate of change in third measurement signal as a function of depth.

19. A method as defined in claim 18, wherein the criterion comprises selection of depths that have a rate of change below a threshold value.

20. A method as defined in claim 1, wherein the simulated second measurement signal is simulated using:

parameters of the formation in which the logging tool is deployed;

parameters of another formation in which the logging tool is not deployed;

or

a constant formation resistivity.

21. A method as defined in claim 1, wherein the first measurement signal corresponds to the transmitter-receiver pair of the second and third measurement signals.

22. A method as defined in claim 1, wherein the logging tool forms part of a logging while drilling or wireline assembly.

23. A method as defined in claim 1, wherein calculating the calibration coefficient further comprises calculating the calibration coefficient at a low angle section of the wellbore, wherein the third measurement signal is acquired from a high angle section of the wellbore.

24. A system comprising processing circuitry to implement the methods of claim 1.

25. A computer-program product comprising instructions which, when executed by at least one processor, causes the processor to perform any the methods of claims 1.