Nested tubular analysis via electromagnetic logging

Patent metadata

Field	Value
Publication number	US-9977144-B2
Application number	US-201615265992-A
Country	US
Kind code	B2
Filing date	Sep 15, 2016
Priority date	Sep 15, 2016
Publication date	May 22, 2018
Grant date	May 22, 2018

Abstract

Methods and apparatus for analyzing nested tubulars via electromagnetic (EM) logging. An example method includes operating an EM logging tool within tubulars nested within a wellbore. The EM logging tool includes an EM transmitter and multiple EM receivers. Data obtained via the EM receivers is utilized to estimate an individual thickness of each tubular at each of multiple depths within the wellbore. The estimated individual thicknesses are utilized to estimate a cumulative thickness of the tubulars at each depth. Local variations of the estimated cumulative thicknesses are utilized to distinguish between actual and spurious indications of differences between the estimated individual thicknesses at neighboring depths.

First claim

What is claimed is:

1. A method comprising:
operating an electromagnetic (EM) logging tool within a plurality of tubulars nested within a wellbore, wherein the EM logging tool comprises an EM transmitter, a first EM receiver, and a second EM receiver;
determining a first apparent cumulative thickness of the tubulars employing data generated via the first EM receiver;
determining a second apparent cumulative thickness of the tubulars employing data generated via the second EM receiver;
producing a deghosted thickness as a minimum of the first and the second apparent cumulative thicknesses;
identifying collar-free sections of the tubulars based on the deghosted thickness;
for each collar-free section, producing an adjusted deghosted apparent cumulative thickness by employing a maximum of the first and second apparent cumulative thicknesses; and
assigning the adjusted deghosted apparent cumulative thickness to the first and second apparent cumulative thicknesses.

2. The method of claim 1 wherein the first and second apparent cumulative thicknesses are each nominal cumulative thicknesses of the tubulars in areas having no collars connecting the tubulars, and having no apparent defects.

3. The method of claim 1 wherein the collar-free sections are identified as being at least a predetermined distance away from a high thickness gradient associated with collars connecting the tubulars.

4. The method of claim 1 wherein the data generated via the first and second EM receivers are attenuation and/or phase.

5. The method of claim 1 wherein spacings between the EM transmitter and the first and second EM receivers are each more than a length of an antenna of the EM transmitter.

6. The method of claim 1 wherein the first and second EM receivers are located respectively at P R1 and P R2 unit lengths from the EM transmitter such that 2.5*OD max <P R1 <P R2 , where OD max is outer diameter of an outermost one of the tubulars.

7. A method comprising:
operating an electromagnetic (EM) logging tool within a plurality of tubulars nested within a wellbore, wherein the EM logging tool comprises an EM transmitter and at least one EM receiver;
determining apparent cumulative thicknesses of the tubulars employing data generated via the at least one EM receiver using measured phase and attenuation; and
identifying relative eccentering of the tubulars based on separations of the apparent cumulative thicknesses from phase and attenuation occurring at the same depth,
wherein at least one of the apparent cumulative thicknesses is greater than a nominal value of the other apparent cumulative thicknesses over a predetermined interval of the data.

8. The method of claim 7 wherein spacing between the EM transmitter and the at least one EM receiver is less than 2.5 times an outer diameter of an outermost one of the tubulars.

9. A method comprising:
operating an electromagnetic (EM) logging tool within a plurality of tubulars nested within a wellbore, wherein the EM logging tool comprises an EM transmitter and a plurality of EM receivers;
utilizing data obtained via the EM receivers to estimate an individual thickness of each tubular at each of a plurality of depths within the wellbore;
utilizing the estimated individual thicknesses to estimate a cumulative thickness of the tubulars at each depth; and
utilizing local variations of the estimated cumulative thicknesses to distinguish between actual and spurious indications of differences between the estimated individual thicknesses at neighboring depths.

10. The method of claim 9 wherein the spurious indications result from dissimilar depth-sensitivities of the EM receivers.

11. The method of claim 9 wherein utilizing the local variations to distinguish between the actual and spurious indications comprises minimizing a cost function, which is a function of candidate ones of the estimated individual thicknesses.

12. The method of claim 11 wherein the cost function enforces conservation of the estimated cumulative thicknesses.

13. The method of claim 11 wherein the cost function penalizes apparent decreases in the estimated individual thicknesses of individual ones of the tubulars relative to sequential ones of the depths when the estimated cumulative thicknesses increase relative to the sequential depths.

14. The method of claim 11 wherein the cost function penalizes apparent increases in the estimated individual thicknesses of individual ones of the tubulars relative to sequential ones of the depths when the estimated cumulative thicknesses decrease relative to the sequential depths.

15. The method of claim 9 wherein:
the EM transmitter is operable to generate a first EM field that generates eddy currents in the tubulars;
the EM receivers are each operable to measure a characteristic of a second EM field generated by the eddy currents;
the tubulars include a first tubular and a second tubular; and
distinguishing between the actual and spurious indications comprises determining:
a first quantity expressing a first cost dependent on a difference between:
a first candidate thickness of the first tubular at a first one of the depths; and
an inversion thickness produced by an inversion of the characteristic employing a numerical casing thickness model;

a second quantity expressing a second cost dependent on a difference between:
the first candidate thickness; and
an average of initially determined thicknesses of the first tubular produced from the inversion employing the model at each of the depths;

a third quantity expressing a third cost dependent on a difference between:
the first candidate thickness; and
a first model thickness of the first tubular at the first depth produced by the model;

a fourth quantity expressing a fourth cost dependent on a difference between:
a sum of the first candidate thickness and a second candidate thickness of the second tubular at the first depth; and
a sum of the first model thickness and a second model thickness of the second tubular at the first depth produced by the model; and

an estimated thickness of the first tubular at the first depth based on a cost function comprising the first, second, third, and fourth quantities.

16. The method of claim 15 wherein the characteristic is a first characteristic, and wherein the EM receivers are each further operable to measure a second characteristic of the second EM field.

17. The method of claim 16 wherein the first and second characteristics are phase and attenuation.

18. The method of claim 15 wherein:
the EM transmitter is a first EM transmitter;
the eddy currents are first eddy currents;
the EM logging tool further comprises a second EM transmitter operable to generate a third EM field that generates second eddy currents in the tubulars; and
the EM receivers are each further operable to measure the characteristic from a fourth EM field generated by the second eddy currents.

19. The method of claim 15 wherein:
a third tubular is nested with the first and second tubulars;
the sum of the first and second candidate thicknesses includes a third candidate thickness of the third tubular at the first depth; and
the sum of the first and second model thicknesses includes a third model thickness of the third tubular at the first depth produced by the model.

Assignees

• Schlumberger Technology Corp

Inventors

• David Martin
• Omar Saad
• Omeragic Dzevat

Classifications

• G01V3/38 Primary

  Processing data, e.g. for analysis, for interpretation, for correction · CPC title

• G01V3/26 Primary

  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 title

• G01V3/30

  operating with electromagnetic waves · CPC title