METHOD AND DEVICE FOR DEPTH POSITIONING DOWNHOLE TOOL AND ASSOCIATED MEASUREMENT LOG OF A HYDROCARBON WELL

Abstract

A depth positioning method to position a production logging tool (1) and a measurement log in a hydrocarbon well (3) in production obtained by means of the tool, the depth positioning method comprises: generating (S1, S2, S3, S1′, S2′, S3′, S11, S12, S13) a set of magnetic measurements (MAG1, MAG) of a depth portion of the hydrocarbon well from a first passive magnetic sensor along the depth portion of the hydrocarbon well, the set of magnetic measurements comprising magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; comparing (S4, S4′, S14) the set of magnetic measurements (MAG1, MAG) to another set of magnetic measurements (MAG_R, MAG2), the other set of magnetic measurements being a reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance (DS) deployed and run in the hydrocarbon well simultaneously; and determining (S4, S4′, S14) the maximum of correlation between the set of magnetic measurements (MAG1, MAG) and the reference set of magnetic measurements (MAG_R, MAG2), the maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion.

Claims

1. A depth positioning method to position a production logging tool and a measurement log in a hydrocarbon well in production obtained by means of said tool, the depth positioning method comprises: generating a set of magnetic measurements of a depth portion of the hydrocarbon well from a first passive magnetic sensor along the depth portion of the hydrocarbon well, the set of magnetic measurements comprising magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; comparing said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being a reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance deployed and run in the hydrocarbon well simultaneously; and determining the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion.

2. The depth positioning method of claim 1, when the reference set of magnetic measurements is generated by the same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, further comprising: determining a depth shift between the two set of magnetic measurements by determining the maximum of correlation in a sliding depth window; calculating a corrected depth log; and correcting a depth positioning scale of a measurements log taken by another sensor responsive to at least one property of a multiphase flow mixture flowing in the hydrocarbon well or at least one property of a formation surrounding the hydrocarbon well based on the corrected depth log and a position of said sensor relatively to the first passive magnetic sensor.

3. The depth positioning method of claim 2, wherein the step of determining a depth shift comprises: a first optimization loop sweeping depth shift values and determining the depth shift which corresponds to a maximum of correlation; and a second optimization loop sweeping depth window values ranging between a depth window of several tens of meters and a depth window of a few meters.

4. The depth positioning method of claim 1, when the reference set of magnetic measurements is generated by the second passive magnetic sensor spaced from the first passive magnetic sensor from the defined distance deployed and run in the hydrocarbon well simultaneously, further comprising: determining a time of flight between the two sets of magnetic measurements by determining the maximum of correlation in a sliding time window; calculating a velocity of the first passive magnetic sensor along the depth portion of the hydrocarbon well; calculating a depth log based on said velocity and a reference initial position; and generating a reference magnetic log by correcting a depth positioning scale of the first set of magnetic measurements based on said depth log.

5. The depth positioning method of claim 4, wherein the step of determining a time of flight comprises: a first optimization loop sweeping time of flight values and determining the time of flight which corresponds to a maximum of correlation; and a second optimization loop sweeping time window values ranging between a time window of several tens of seconds and a time window of a few seconds.

6. The depth positioning method of claim 4, further comprising: generating a first set of positioning measurements associated with the set of magnetic measurements of the first passive magnetic sensor, and a second set of positioning measurements associated with the set of magnetic measurements of the second passive magnetic sensor, the two sets of positioning measurements being generated by a first positioning sensor and a second positioning sensor close to the first passive magnetic sensor and the second passive magnetic sensor that are deployed and run in the hydrocarbon well simultaneously, respectively; computing the magnetic measurements in a cylindrical or spherical coordinates system; and generating a reference magnetic log for each of the radial distance, the azimuth and the height according to the cylindrical coordinates system, or the radius, the elevation and the azimuth according to the spherical coordinates system.

7. A method of determining a velocity of a production logging tool deployed and run through a hydrocarbon well in production along a depth portion of the hydrocarbon well, the production logging tool comprising at least two passive magnetic sensors, said velocity determination method comprises: generating a set of magnetic measurements of a depth portion of the hydrocarbon well from a first passive magnetic sensor along the depth portion of the hydrocarbon well, the set of magnetic measurements comprising magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; comparing said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being a reference set of magnetic measurements generated either by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance deployed and run in the hydrocarbon well simultaneously; determining the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion; determining a time of flight between the two sets of magnetic measurements by determining the maximum of correlation in a sliding time window; and calculating a velocity of the first passive magnetic sensor along the depth portion of the hydrocarbon well.

8. A method of determining a density of wellbore fluid flowing into a depth portion of a hydrocarbon well in production by correcting a depth positioning scale of a pressure gradient measurements log obtained from a pressure sensor by firstly, implementing a depth positioning method comprising: generating a set of magnetic measurements of a depth portion of the hydrocarbon well from a first passive magnetic sensor along the depth portion of the hydrocarbon well, the set of magnetic measurements comprising magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; comparing said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being a reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance deployed and run in the hydrocarbon well simultaneously; and determining the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion; and secondly, calculating the density by dividing the pressure gradient by earth gravity, eventually corrected by the cosine of an hydrocarbon well inclination in case of deviated hydrocarbon well.

9. A method of evaluating hydrocarbon well integrity by comparing a reference set of magnetic measurements taken at an earlier time corresponding to an undamaged well casing, to a subsequent set of magnetic measurements showing magnetic anomalies corresponding to a damaged well casing and relating said anomalies to damaged well casing portions depths by implementing a depth positioning method comprising: generating a set of magnetic measurements of a depth portion of the hydrocarbon well from a first passive magnetic sensor along the depth portion of the hydrocarbon well, the set of magnetic measurements comprising magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; comparing said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being the reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance deployed and run in the hydrocarbon well simultaneously; and determining the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion.

10. A depth positioning device to position a production logging tool and a measurement log in a hydrocarbon well in production obtained by means of said tool, the depth positioning device comprises: a first passive magnetic sensor arranged to generate a set of magnetic measurements of a depth portion of the hydrocarbon well, the set of magnetic measurements comprising multiple magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; means for deploying and running the first passive magnetic sensor along the depth portion of the hydrocarbon well; and a processing unit: arranged to compare said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being a reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance so as to be deployed and run in the hydrocarbon well simultaneously, and arranged to determine the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion.

11. The depth positioning device of claim 10, further comprising a first positioning sensor close to the first passive magnetic sensor and a second positioning sensor close to the second passive magnetic sensor.

12. The depth positioning device of claim 10, comprising at least one electronic board including a quartz oscillator, a memory, the passive magnetic sensor realized as a three axis magnetometer chip, a positioning sensor realized as a three axis accelerometer chip, all being connected to the processing unit realized as a microcontroller.

13. The depth positioning device of claim 12, comprising two electronic boards positioned at the defined distance from each other.

14. A production logging tool comprising a depth positioning device to position a production logging tool and a measurement log in a hydrocarbon well in production obtained by means of said tool, the depth positioning device comprises: a first passive magnetic sensor arranged to generate a set of magnetic measurements of a depth portion of the hydrocarbon well, the set of magnetic measurements comprising multiple magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; means for deploying and running the first passive magnetic sensor along the depth portion of the hydrocarbon well; a processing unit: arranged to compare said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being a reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance so as to be deployed and run in the hydrocarbon well simultaneously; and arranged to determine the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion; and at least one sensor responsive to at least one property of a multiphase flow mixture flowing in the hydrocarbon well or at least one property of a formation surrounding the hydrocarbon well.

15. A recording ball comprising a protective shell of spherical form having an average density such that it can be swept along the hydrocarbon well with a multiphase flow mixture flowing in the hydrocarbon well, a battery, an electronic board connected to at least one sensor responsive to at least one property of the multiphase flow mixture or at least one property of a formation surrounding the hydrocarbon well and to a depth positioning device comprising: a first passive magnetic sensor arranged to generate a set of magnetic measurements of a depth portion of the hydrocarbon well, the set of magnetic measurements comprising multiple magnitude and/or direction measurements of the magnetic field that forms a characteristic magnetic field pattern representative of a surrounding magnetic environment of the hydrocarbon well all along the depth portion; means for deploying and running the first passive magnetic sensor along the depth portion of the hydrocarbon well; and a processing unit: arranged to compare said set of magnetic measurements to another set of magnetic measurements, the other set of magnetic measurements being a reference set of magnetic measurements generated either by a same or similar passive magnetic sensor deployed and run in the hydrocarbon well earlier, or by a second passive magnetic sensor spaced from the first passive magnetic sensor from a defined distance so as to be deployed and run in the hydrocarbon well simultaneously; and arranged to determine the maximum of correlation between the set of magnetic measurements and the reference set of magnetic measurements, said maximum being related to identifiable characteristic magnetic field pattern over a part of the depth portion.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0070] The present invention is illustrated by way of examples and not limited to the accompanying drawings, in which like references indicate similar elements:

[0071] FIG. 1 is a cross-section view schematically illustrating a production logging tool including a depth positioning device deployed into a well bore of a hydrocarbon well in production;

[0072] FIG. 2 is a perspective view of a production logging tool including a depth positioning device;

[0073] FIG. 3 is a perspective and transparent view showing the depth positioning device in the production logging tool of FIG. 2;

[0074] FIG. 4 is an enlarged perspective view of the electronic board of the depth positioning device of FIG. 3;

[0075] FIG. 5 is an exploded perspective view showing the depth positioning device in a flowable recorder subs or recording ball;

[0076] FIGS. 6 to 8 schematically illustrate various embodiments of the depth positioning method;

[0077] FIGS. 9 to 13 are diagrams illustrating typical magnetic signatures measured with the depth positioning device of the invention and used to implement at least one embodiment of the depth positioning method of the invention.

DETAILED DESCRIPTION

[0078] The invention will be understood from the following description, in which reference is made to the accompanying drawings.

[0079] FIG. 1 is a cross-section view schematically illustrating a production logging tool 1 including a depth positioning device 11 deployed into a well bore 2 of a hydrocarbon well 3 that has been drilled into an earth formation 4. The well bore refers to the drilled hole or borehole, including the open hole or uncased portion of the well. The borehole refers to the inside diameter of the wellbore wall, the rock face that bounds the drilled hole. The open hole refers to the uncased portion of a well. While most completions are cased, some are open, especially in horizontal or extended-reach wells where it may not be possible to cement casing efficiently. The depth positioning device 11 is suitable for performing any embodiment of the depth positioning method of the invention in a hydrocarbon well in a production phase. As an example, this depth positioning device 11 may be incorporated into the production logging tool 1. The production logging tool 1 may comprise various sub sections 5 having different functionalities, a centralizer 6 and coupled to surface equipments through a wireline 7. At least one sub section comprises a measuring device generating measurements logs, namely measurements versus depth or time, or both, of one or more physical quantities in or around a well. Wireline logs are taken downhole, transmitted through a wireline to surface and recorded there. Surface equipments are well known in the oilfield industry, thus not shown and described in details herein. There are numerous log measurements (e.g. electrical properties including resistivity and conductivity at various frequencies, sonic properties, active and passive nuclear measurements, dimensional measurements of the wellbore, formation fluid sampling, formation pressure measurement, etc.) possible with such a production logging tool 1 while it is displaced along and within the hydrocarbon well 3 drilled into the subterranean formation 4. The well bore 2 comprises a cased portion 8. The cased portion 8 may comprise corroded zone 9 (damaged well casing section) and perforated zone 10. Various fluid (that may include solid particles) entries F1, F2 may occur from the subterranean formation 4 towards the well bore 2.

[0080] FIG. 2 is a perspective view of the production logging tool 1 including a depth positioning device 11. The production logging tool 1 comprises a top section 21, a centralizer 22 and a bottom section 23. The bottom and top sections 21, 23 comprises appropriate connection means 24 (only one being visible in FIG. 2) to other sections of the tool, and/or other tools (string of tools) and/or tractor means and/or line for communication with surface equipment. The production logging tool 1 typically comprises various sensors 5 disposed inside the tool housing and/or along the tool housing and/or connected to the arms of the centralizer. Those sensors measure various parameters of the fluid F1, F2 inside the well bore 2 and/or flowing from the subterranean formation 4 around the well bore 2 as usual in the art (e.g. pressure, temperature, fluid density, fluid velocity, fluid conductivity, etc. . . . ).

[0081] Several sensors can be placed at the top, middle and bottom of the production logging tool in order to allow tool velocity measurement from time of flight measurement of magnetic field anomalies.

[0082] FIG. 3 is a perspective, exploded and transparent view showing an exemplary embodiment of the depth positioning device 11 in the production logging tool 1 of FIG. 2. The bottom section 23 comprises a mounting chassis 25 for supporting and mounting the electronic board 26 of the depth positioning device 11. The electronic board 26 has a circular shape. Other electronic boards associated with other sensors or devices of the production logging tool may be mounted in at a distance above and/or below the electronic board 26 of the depth positioning device 11.

[0083] FIG. 4 is an enlarged perspective view of an exemplary embodiment of the electronic board 26 of the depth positioning device 11 of FIG. 3. The electronic board 26 comprises several holes 27 for securing the board to the mounting chassis 25 and passing appropriate wire connectors (e.g. power and data/not shown). In a first embodiment, the electronic board 26 comprises a passive magnetic sensor 28, a processing unit 29, a memory 30 and a quartz oscillator 31. The passive magnetic sensor 28 may be a MEMS magnetometer integrated circuit, either a single-axis, or a dual-axis or a three-axis magnetometer. The processing unit 29 may be a microcontroller. In another embodiment, the electronic board 26 may further comprise an accelerometer and/or a gyroscope, for example a MEMS three axis accelerometer-gyroscope integrated circuit 32 (i.e. grouping both functions of 3-axis gyroscope and a 3-axis accelerometer).

[0084] A further depth positioning device 11 comprising a second passive magnetic sensor may be secured into the top section 21 of the production logging tool 1 in a similar fashion to the first passive magnetic sensor 28 into the bottom section 23. In this case, the two passive magnetic sensors are separated from each other by a fixed and defined distance DS, for example one meter in the production logging tool example of FIG. 2.

[0085] The housing of the production logging tool 1 is suitably made of non magnetic material such as stainless steel (e.g. stainless steel commercialized under the Inconel trademark) in order to minimize the effect of tool housing/mechanics on the passive magnetic sensor measurements. The centralizer 22 offers good tool centralization in order to have the sensor always positioned at the same place in the wellbore between successive passes and to measure stable earth magnetic field anomalies. However, as an alternative, acceptable measurement may also be obtained with a production logging tool that does not include a centralizer.

[0086] FIG. 5 is an exploded perspective view showing the depth positioning device in a flowable recorder subs or recording ball 40. The recording ball 40 is an autonomous measuring device that may be released downhole into the well bore to be transported to the surface through the fluids and collected at the surface (e.g. at the wellhead). The launch of the recording ball can be programmed in advance at fixed times or based on events detected downhole. On his way to the surface the recording ball will perform various measurements. The recording ball is prevented from remaining downhole by having an average density low enough so that it can be swept along the well with the flow for example less than 1.8 g/cc. Such recording balls can provide downhole data at critical times of operations of the hydrocarbon well and at places where it is impossible to place cables of electric or optical communications. For example, such recording balls enable controlling the operations of hydraulic multi-zone fracturing in horizontal and multilateral wells. A recording ball 40 comprises a protective shell 41 that can be in the form of a hollow sphere made of a material such as titanium, in order to offer a sufficient resistance to pressure while minimizing the wall thickness. Such a sphere may have a diameter ranging from 2 cm to 5 cm. The recording ball 40 comprises internally to the shell 41 a battery and a battery support 42, an electronic board 43 and electronic board support 45 including the depth positioning device 11 according to the invention, an electronic processor and a memory. Various sensors 44 (e.g. a pressure, a temperature sensor, etc. . . . ) connected to the electronic board 43 may be coupled to the outside of the shell 41. The shell 41 may be formed by two half-spheres that are securely and water-tightly coupled together by appropriate securing means 46 and seals 47. The inertial sensors, gyroscopes and accelerometers, and magnetometers of the positioning device 11 are used to calculate the speed and trajectory of the recording ball during its ascent to the surface. This information may provide guidance on fluid inputs along the well, especially by measuring the acceleration of the module with the flow.

[0087] FIGS. 6 to 8 schematically illustrate various embodiments of the depth positioning method.

[0088] FIG. 6 schematically illustrates a first embodiment of the depth positioning method. This embodiment requires the use of two passive magnetic sensors, the first and second passive magnetic sensor being three-axis magnetometer generating signals in the three dimensions separated by a defined distance DS. The data acquisition sequencing scanning period (the inverse of the scanning rate SR) is related to the time interval between two measurements made at time t.sub.i and t.sub.i+1, namely t.sub.i+1−t.sub.i=SP=1/SR, for example SP is 0.1 second. This is accurately controlled by the processing unit 29 connected to the quartz oscillator 31. In a first step S1, the first magnetic sensor provides first signals MAG1x(t.sub.i), MAG1y(t.sub.i), MAG1z(t.sub.i) corresponding to the magnetic field in the three dimensions at a first position X1 and the second magnetic sensor provides second signals MAG2x(t.sub.i), MAG2y(t.sub.i), MAG2z(t.sub.i) corresponding to the magnetic field in the three dimensions at a second position X2. In a second step S2, the first signals and the second signals are filtered (for example to reduce the noise from the signals) and the modulus is calculated (square root of MAG1x(t.sub.i).sup.2+MAG1y(t.sub.i).sup.2+MAG1z(t.sub.i).sup.2 and, respectively, square root of MAG2x(t.sub.i).sup.2+MAG2y(t.sub.i).sup.2+MAG2z(t.sub.i).sup.2). In a third step S3, the first and second filtered signals MAG1_F(t.sub.i) and MAG2_F(t.sub.i) are buffered in the memory 30. The entire measuring job or a time portion of a measuring job may be stored in memory. Thus, after a defined time interval, the memory contains two sets of magnetic measurements associated with the first and second magnetic sensors. In a fourth step S4, features or patterns in the magnetic field measured by the first magnetic sensor at time t.sub.i are recognized by comparison with the magnetic field measured by the second sensor at a later time t.sub.i+t.sub.fj. Pattern recognition and time delay or time of flight TF(i) computation is performed by defining a sliding time window TW.sub.k on the magnetic measurements data and calculating a correlation value. A first optimization loop (No.1) generates incrementing time of flight values t.sub.fj and the processing unit computes the following summation formula and finds the time of flight value TF(i) that corresponds to a maximum of the sum indicating the best possible correlation (i.e. the time delay that maximizes the correlation value):

[00001]$\underset{{\mathrm{TW}}_k}{.Math.}.Math..Math.\mathrm{MAG}.Math..Math.1.Math.\mathrm{\_F}.Math.\left(t_i\right)\times \mathrm{MAG}.Math..Math.2.Math.\mathrm{\_F}.Math.\left(t_i+t_{\mathrm{fj}}\right)$

The time of flight values of the first optimization loop are comprised in a time window covering the time of flight estimated from wireline cable speed plus and minus a certain percentage, typically 20%. The maximum value is obtained for optimal fit between signature curves in the chosen time window TW.sub.k. The time window should be large enough to include identifiable patterns and short enough to correspond to a constant tool velocity. Although depending on well, logging and tool characteristics, the time window TW.sub.k is typically chosen in a range of a few seconds to several tens of seconds. An efficient way to determine the optimal time window TW uses a second optimization loops (No.2). The time window TW.sub.k is decremented in steps starting with a time window TW.sub.0 of several tens of seconds and then narrowed down to a time window TW.sub.f of a few seconds. Alternatively, incrementing from a time window TW.sub.f of a few seconds to a time window TW.sub.0 of several tens of seconds is also possible. The optimal time window TW is given for the maximum correlation value hereinbefore calculated.
As a result, in a fifth step S5, the time of flight value TF(i) allows computing the tool velocity V(t.sub.i) of the production logging tool along the well bore, namely:

V(t.sub.i)=(X2−X1)/TF(i)=DS/TF(i)

Then, by an integration calculation, it is possible to calculate the distance run by the production logging tool. In a sixth step S6, a depth log (DEPTH LOG) is calculated based on said tool velocity V(t.sub.i) and a reference initial position DEPTH.sub.0, namely:

[00002]$\mathrm{DEPTH}\left(t_i\right)=\mathrm{DEPTH}.Math..Math.0+\underset{i}{.Math.}.Math..Math.V\left(t_i\right)\times \mathrm{SP}$

The reference position DEPTH0 may be either zero, i.e. the depth at surface or wellhead, or an arbitrary position close to a zone of interest (for example the position of a completion element such as a liner diameter change). In a seventh step S7, a reference magnetic log MAG_R(DEPTH(t.sub.i)) is generated which will be used to accurately position tools and correct measurement logs from other passes and other runs.

[0089] Thus, the magnetic field log correlation can be used to obtain an improved depth accuracy (and not just repeatability). In order to achieve this instead of measuring the magnetic field at a single location in the tool at least two measurements separated by a known distance are performed. With a pair or more sensors distributed along the length of the production logging tool, the recognition of magnetic signatures with a time delay between two sensors allows computing a robust tool velocity using the time of flight determination technique. This velocity measurement is unaffected by wireline cable length errors and provides the basis for an accurate magnetic reference log. The only requirement is to define a reference starting point, preferably the depth reference point chosen just above the production zone where data is the most important. In addition, a location that has a particular outstanding magnetic field pattern signature is advantageous in order to facilitate identification during future operations. Depth below that reference depth is computed by time integrating tool velocity. All future magnetic field logs will be correlated with respect to this log.

[0090] Having an accurate depth allows deriving new measurements and giving further more insight on well conditions. As an example, from a simple pressure measurement we can extract the density of fluid present inside the wellbore provided that depth is known with high precision. Indeed the pressure gradient, i.e. the variation of pressure with depth is a direct measurement of density multiplied by the earth gravity for a vertical wellbore. In case of deviated wellbore, the result is corrected by the cosine of the inclination. With state of the art depth measurement performance poor results are obtained and operator often uses nuclear tools based on gamma ray attenuation to measure fluid density. With depth logs obtained with the method of the invention, the accuracy on fluid density competes with nuclear technology at no extra cost on operations and no risk for the environment. Further, knowing tool velocity allows calibrating flow sensors that measure fluid velocity relatively to the tool and not relatively to the wellbore.

[0091] FIG. 7 schematically illustrates another embodiment of the depth positioning method. This embodiment differs from the first embodiment in that the first and second passive magnetic sensor are three-axis magnetometer coupled to a three-axis accelerometer-gyroscope sensor generating magnetic and acceleration signals in the three dimensions, respectively. Thus, in the first step S1′, the first magnetic sensor provides first signals MAG1x(t.sub.i), MAG1y(t.sub.i), MAG1z(t.sub.i) corresponding to the magnetic field in the three dimensions. Further, the second magnetic sensor provides second signals MAG2x(t.sub.i), MAG2y(t.sub.i), MAG2z(t.sub.i) corresponding to the magnetic field in the three dimensions. The accelerometer sensor provides first signals ACC1x(t.sub.i), ACC1y(t.sub.i), ACC1z(t.sub.i) corresponding to the acceleration in the three dimensions. A gyroscope can be added or integrated to the accelerometer in order to compute a robust and accurate acceleration vector even when the tool moves or vibrates. In the second step S2′, the first signals and the second signals are filtered and the modulus IMAG1I(t.sub.i), IMAG2I(t.sub.i), the elevation MAG1θ(t.sub.i), MAG2θ(t.sub.i) and the azimuth MAG1φ(t.sub.i), MAG2φ(t.sub.i) values of the magnetic field according to a spherical coordinates system are calculated. Also, the tool inclination θ(ti) and the tool azimuth φ(ti) can be determined from the accelerometer-gyroscope measurements. Subsequently, the steps are identical to the first embodiment except that three reference magnetic logs in modulus IMAG_RI(DEPTH(t.sub.i)), in elevation MAGθ_R(DEPTH(t.sub.i)) and in azimuth MAGφ_R(DEPTH(t.sub.i)) can be generated by correcting a depth positioning scale of one of the sets of magnetic measurements based on the depth log DEPTH(t.sub.i) in spherical coordinates system (step S7′). Alternatively, in a similar fashion, the correlation analysis may also be performed on the three-axis of the magnetic field vector or any angles with respect to the axis of the well-bore. Correlation on the vector direction (e.g. elevation, azimuth) gives other details on magnetic signatures and further improved capabilities to detect anisotropic anomalies. This is advantageous when logging through completion equipments which have non axis-symmetric shapes such as side pocket mandrels or monitoring pipe or casing damages of deviated well bore sections where corrosion often occurs due to water stagnation at the bottom part of the pipe or casing.

[0092] FIG. 8 schematically illustrates still another embodiment of the depth positioning method. This embodiment requires the use of a single passive magnetic sensor, and the earlier generation of a first set of magnetic measurements (step S0) to produce a reference magnetic log MAG_R(DEPTH). As in the other embodiment, the data acquisition sequencing scanning rate SR is related to the time interval between two measurements made at time t.sub.i and t.sub.i+1, namely t.sub.i+1−t.sub.i=SP=1/SR, for example SP is 0.1 second. In a first step S11, the magnetic sensor provides a signal MAG(t.sub.i) corresponding to the modulus of the magnetic field at a reference position for the tool string, ie the position of the magnetic sensor. In a second step S12, the signal MAG(t.sub.i) is filtered. In a third step S13, the filtered signals MAG_F(t.sub.i) are buffered in the memory 30. After a defined time interval, the memory contains a second set of magnetic measurements associated to a depth DEPTH_W(t.sub.i) estimated by, for example, the wireline depth measurement system (see details in the background section). It is to be noted that the wireline depth measurement system may provide measurements either in real time (simultaneously or quasi-simultaneously with the passive magnetic sensor), or at a later time when operating as a recorder (the respective acquisition of the wireline depth measurement system and of the passive magnetic sensor resulting from two separate acquisition systems). This second set of magnetic measurements constitutes an uncorrected magnetic log MAG_F(DEPTH_W). In a fourth step S14, features or patterns in the magnetic field measured by the magnetic sensor at depth DEPTH_W are recognized by comparison with the magnetic field from the reference magnetic log MAG_R(DEPTH). Pattern recognition and depth shift DEPTH_SHIFT(j) computation is performed by defining a sliding depth window DW.sub.k on the magnetic measurements data and calculating a correlation value. A first optimization loop (No.1) generates incrementing depth shift values DEPTH_SHIFT(j) and the processing unit computes the following summation formula and finds the depth shift DEPTH_SHIFT which corresponds to a maximum of the sum indicating the best possible correlation (i.e. the depth shift value that maximizes the correlation value) within the corresponding depth window DW.sub.k:

[00003]$\underset{{\mathrm{DW}}_k}{.Math.}.Math..Math.\mathrm{MAG\_R}.Math.\left(\mathrm{DEPTH\_W}.Math.\left(i\right)\right)\times \mathrm{MAG\_F}.Math.\left(\mathrm{DEPTH\_W}.Math.\left(i\right)+\mathrm{DEPTH\_SHIFT}.Math.\left(j\right)\right)$

Such correlation calculation is done by the product of the shifted and unshifted curves over a window DW.sub.k. The maximum value is obtained for optimal fit between signature curves in the chosen depth window DW.sub.k. The depth window should include identifiable patterns which can be associated to a section of the well with a high level of confidence, i.e. with a very low probability that another section of the well has similar pattern or signature. In practice, the optimal depth window DW is the largest possible which includes unique well patterns, possibly several tens of meters long, but small enough so that depth correction stays constant within this depth window (which is related to the accuracy of the wireline depth). Both a high confidence on position and a high spatial resolution can be achieved on corrected logs by using this method. An efficient way to determine the optimal depth window DW uses a second optimization loops (No.2). The depth window DW.sub.k is decremented in steps starting with a depth window DW.sub.0 of several tens of meters and then narrowed down to a depth window DW.sub.f of a few meters. Alternatively, incrementing from a depth window DW.sub.f of a few meters to a depth window DW.sub.0 of several tens of meters is also possible. The optimal depth window DW is given for the maximum correlation value hereinbefore calculated.

[0093] As a result, in a fifth step S15, the depth shift value DEPTH_SHIFT(i) allows computing a corrected depth log DEPTH_C(i), namely:

DEPTH_C(i)=DEPTH_W(i)+DEPTH_SHIFT(i)

In a sixth step S16, a corrected magnetic log MAG_F(DEPTH_C) is calculated based on said corrected depth log DEPTH_C(i). In a seventh step S17, all measurements logs taken by other sensors of the production logging tool can be corrected regarding the depth positioning by recomputing with the corrected depth log DEPTH_C(i) based on the position of the concerned sensor relative to the passive magnetic sensor (distance X between the first passive magnetic sensor and the other sensor).

[0094] In the case of a production logging tool operating in a recorder mode, the “wireline depth” and the “magnetic depth” are acquired from two separate acquisition systems which generate two data files versus time. These data files are merged together after the production logging tool is retrieved at the surface and the tool memory is downloaded. The file merging step generates a file with magnetic measurements that are synchronized versus wireline depths (during the third step S13), all subsequent steps of FIG. 8 being the same.

[0095] FIGS. 9 to 13 are diagrams illustrating typical magnetic signatures measured with the depth positioning device of the invention and used to implement at least one embodiment of the depth positioning method of the invention.

[0096] FIG. 9 shows an example of the magnetic measurement logs MAG (full line) in a gas well in comparison with CCL measurements (dotted line) and Gamma Ray GR measurements (dash line) for a depth interval from 5259 m to 5319 m. The CCL measurements have large peaks corresponding to the collars locations, only those large peaks are repeatable while unstable signals can be seen in-between. The Gamma Ray measurements are poorly interpretable in such a short depth interval of around 60 m. Unlike CCL and GR measurements, the magnetic measurement log according to the invention contains high resolution features/patterns that are repeatable and identifiable both at large scale of over hundreds meters down to sub-meter resolution. The magnetic log provides a unique signature of the well in its entirety and also within its portions, the magnetic log representing the fingerprint of the well. The large range of length scales of information-rich patterns (patterns with very low probability to be reproduced elsewhere in the same well or in another well) allows accurate and reliable determination of the position at which those patterns correspond. This remarkable characteristic is related to the fact that the magnetic field in the wellbore is influenced by several phenomena which also have a large range of length scales such as the earth magnetic field itself with its anomalies, presence of magnetized rock layers, proximity to completion pipes (casing, tubing, joints, mandrels, screens, etc.), geometries and material properties, etc. . . . .

[0097] FIG. 10 shows two passes (up and down passes) in a gas well of a production logging tool including a CCL device and a magnetic sensor of a depth positioning device, namely magnetic measurements MAG (top signals MAG_PASS_DWN1 and MAG_PASS_UP1) in comparison with CCL measurements (bottom signals CCL_PASS_DWN1 and CCL_PASS_UP1). The up and down passes MAG_PASS_DWN1 and MAG_PASS_UP1 demonstrate that the magnetic signature is repeatable since both signals resulting from up and down passes fairly superpose each other.

[0098] FIG. 11 shows two passes (up and down passes) of a production logging tool including a magnetic sensor of a depth positioning device, the measurements of the two passes being taken at different speed, in this example respectively 10 and 20 meters per minute (full line MAG_PASS_DWN1 and dotted line MAG_PASS_UP2). It is to be noted that in the initial acquisition the magnetic signatures from both passes do not fit. An analysis shows that this is due to a reference depth given by the wireline system that has an error of several meters. FIG. 12 illustrates that applying a correction of 4.5 m on the wireline reference values allows obtaining almost a perfect match in the depth interval from 5300 m to 5310 m (between both signals MAG_PASS_DWN1 in full line and MAG_PASS_UP2 DEPTH CORRECTED in dotted line). The correction is obtained with the embodiment hereinbefore described in relation with FIG. 8. More generally pattern recognition algorithms can be used to perform a continuous depth logs correction by defining a sliding depth window DW (an example of depth window DW is depicted by a dash-line rectangle in FIG. 12) on the magnetic signature and determining the depth shift that maximizes the correlation. The correlation method allows defining an accurate depth reference for the logs which cannot be achieved solely with Gamma Ray and CCL conventional methods. Thus, the interpretation of measurement logs performed by other sensors (pressure, temperature, density, conductivity, etc. . . . ) and remedial actions planning are significantly improved.

[0099] FIG. 13 represents the signals MAG_SENSOR1 and MAG_SENSOR2 of two passive magnetic sensors spaced by one meter. By shifting in time the signal of the second sensor MAG_SENSOR2_DELAYED after implementing the depth positioning method in accordance with the first embodiment of the depth positioning method (see FIG. 5) and determining the time of flight TF(i), it is found that the patterns MAG_SENSOR1 and MAG_SENSOR2_DELAYED line up.

[0100] It should be appreciated that embodiments of the production logging tool according to the present invention are not limited to the embodiment showing vertical hydrocarbon well bore, the invention being also applicable whatever the configuration of the well bore, namely horizontal, deviated or a combination of vertical, deviated and/or horizontal portions, cased or uncased. Also, the magnetic depth positioning device of the invention is not limited to an application to a production logging tool, but can be easily adapted to various applications to analysis tools operating at downhole pressure and temperature conditions, e.g. a wireline tool, a tool that is connected to a tractor, kickover tools which deploy gas lift valves or gauges in side pocket mandrels, plugs, cutter tools, etc. . . . . For complex well completion configurations having, valves, gas lift mandrels, pumps, chemical injectors, sand screens, etc. . . . where the deployment of lines, cables, rods or tubings is difficult or impossible, magnetic measurements may be performed by autonomous miniature recording subs that travel though the well and are flowed back to surface and retrieved for downloading the registered magnetic measurements, simultaneously with other measurements related to the fluid or the formation. All those tools would greatly benefit from the integration of the depth positioning device and method of the invention in order to help locating the precise position for the intervention.