System, method and computer-program product for in-situ calibration of a wellbore resistivity logging tool

• US 10,444,404 B2
• Filed: 07/26/2013
• Issued: 10/15/2019
• 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
• Primary Examiner(s): Phan, Huy Q
• Assistant Examiner(s): Dickinson, Dustin R
• Application Number:
  US14/427,174
• Publication Number:
  US 20150241596A1
• Time in Patent Office: 2,272 Days
• 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 performing a wellbore operation using in-situ calibration of a logging tool deployed along a wellbore, the method comprising:

extending the logging tool, coupled to a control center, into the wellbore positioned within a hydrocarbon-bearing formation;

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

simulating, via the control center, a second measurement signal of the formation;

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

acquiring, via the logging tool, 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;

while the logging tool is within the wellbore, calibrating the acquired third measurement signal using the calibration coefficients inverting the calibrated third measurement signal to generate petrophysical characteristics of the formation; and

using the petrophysical characteristics to perform at least one of a wellbore placement operation, wellbore drilling operation, wellbore landing operation, or geo-steering operation.

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; and

the deep measurement signals are acquired using two antennas spaced at least 600 inches apart axially along the logging tool.

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 in 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, further comprising transmitting the calibrated third measurement signal, via a telemetry sub disposed downhole, to a component at a remote location which is configured to receive the third measurement signal.

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 any of the methods in claims 1-23.

25. A non-transitory computer-program product comprising instructions which, when executed by at least one processor, causes the processor to perform any of the methods in claims 1-23.