METHOD AND DEVICE FOR IDENTIFICATION OF FLUIDS BEHIND A TUBING

专利摘要:
The present disclosure relates to the determination of an annular material in a wellbore (108, 502), which comprises measuring an acoustic noise of at least one reference material and which produces at least one acoustic profile (P1, P2, P3) corresponding, monitoring the annular material with at least one acoustic sensor (138) positioned in the wellbore (108, 502) so as to obtain an acoustic response of the annular material, the comparison of the acoustic response with the at least one acoustic profile (P1, P2, P3) using a processor (710) communicatively coupled to the at least one acoustic sensor (138), and characterizing the annular material based on the comparison of the response acoustic with the at least one acoustic profile (P1, P2, P3).
公开号:FR3040426A1
申请号:FR1657170
申请日:2016-07-26
公开日:2017-03-03
发明作者:Krishna M Ravi；Li Gao；Christopher Lee Stokely
申请人:Halliburton Energy Services Inc；
IPC主号:

专利说明:

CONTEXT
The completion of an oil or gas well often includes a cementing procedure to allow the connection of casings lining a well to the formation. During this procedure, the cement slurry is pumped to the bottom of the hole in the wellbore casing and then returned to the top of the hole by a wellbore annulus defined between the wellbore casing and a well wall. drilling. The cement suspension displaces other fluids as it travels through the casing and into the annulus. In reverse cementing operations, the cement is actually pumped into the annulus and then up to the surface location through the inside of the casing.
A judicious placement of the cement suspension in the annular space of the wellbore covers the underground fluid zones, in order to recover efficiently and safely hydrocarbons from the well. After placement, the cement suspension undergoes a hydration reaction during which the cement suspension passes from the liquid state to a solid state. Monitoring the placement of the cement slurry and its transition from the liquid state to the solid state can help determine when the cement slurry has hardened and is ready for subsequent operation in the well. This can result in good cement quality, improved mud extraction, improved well integrity, and savings in time and money.
The solidified cement suspension forms a cement sheath, which is subject to constraints during subsequent operations performed on the well. Monitoring the integrity of the cement sheath once the cement slurry has hardened also contributes to the safety and economy of the well, and helps modify bottom hole operations to optimize well production. For example, a hydraulic fracturing operation can be monitored, evaluated and modified as needed to ensure proper placement of fractures. In another example, if water is detected in the area near the wellbore, then perforations close to the area may be automatically stopped during a full automatic completion facility.
[0004] No technique exists at the present time for monitoring the downhole of the extraction of drilling fluid from the annular space, the placement of the cement suspension and the successive integrity of the wells. . Some of the existing techniques involve placement of electronic devices behind the casing to track fluid and cement flow during and after a cementing operation. Among these techniques, the electronic devices obtain measurement data from radiofrequency identification marks (RFIDs) dispersed in the cement or mud as these fluids flow into the annular space. In other cases, the electronic devices measure the dielectric properties of the fluids flowing in the annular space.
These measurements are based on the emission of a high frequency electromagnetic wave (EM) energy in the fluids present in the annular space. EM waves of high frequency undergo significant attenuation in the wellbore fluids, for example in the form of suspension of sludge and water-based cement. As a result, the investigative depth of devices using high frequency EM waves is typically low. In addition, to compensate for the loss of energy, more power is needed to transmit electromagnetic energy into the fluids to increase the depth of investigation. In the absence of a readily available energy source behind the casing, this power requirement involves the design and operation of active electronic devices behind the casing.
PRESENTATION
In one or more embodiment (s) of the present disclosure, a method, in particular a method for characterizing a material, comprises: measuring an acoustic noise produced by at least one reference material in such a way as to producing at least one corresponding acoustic profile; monitoring an annular material in a wellbore drilled through at least one formation with at least one acoustic sensor positioned in the wellbore, so as to obtain an acoustic response of the annular material; comparing the acoustic response with the at least one acoustic profile using a processor coupled in communication with the at least one acoustic sensor; and characterizing the annular material based on the comparison of the acoustic response and the at least one acoustic profile.
In one or more embodiments of the present disclosure, the monitoring of the annular material in the wellbore includes monitoring at least one of a drilling fluid, a separating fluid, a a suspension of cement and a cement sheath located in an annular space defined by the wellbore, and at least one fluid that flows from the at least one formation to the wellbore.
In one or more embodiment (s) of the present disclosure, the measurement of the acoustic noise produced by the at least one reference material comprises the measurement of the acoustic noise produced as a function of at least one of a flow rate. , a density, a type, a viscosity and a phase of Tau least one reference material.
In one or more embodiment (s) of the present disclosure, obtaining the acoustic response of the annular material comprises analyzing an acoustic noise signature of the annular material in the wellbore to obtain the acoustic response.
In one or more embodiment (s) of the present disclosure, the acoustic sensor comprises an array of electronic sensors, and wherein the monitoring of the annular material with the at least one acoustic sensor comprises obtaining the acoustic response of the acoustic sensor. annular material using the matrix of electronic sensors.
In one or more embodiments of the present disclosure, the characterization of the annular material includes the characterization of a type of annular material, and the method further comprises transmitting the annular material type in real time to a location. surface, and / or recording the type of annular material in the acoustic sensor.
In one or more embodiments of the present disclosure, the acoustic sensor comprises a plurality of acoustic sensors positioned in the wellbore at known locations, and the method further comprises: assigning a unique identifier to each acoustic sensor of the plurality of acoustic sensors, the unique identifier being correlated to the known location of each acoustic sensor, and determining a location of the annular material in the wellbore according to the unique identifier.
In one or more embodiment (s) of the present disclosure, the at least one acoustic profile is recorded at a surface location and / or in a memory device included in the acoustic sensor.
In one or more embodiments of the present disclosure, the processor is at a surface position or in the wellbore.
In one or more embodiments of the present disclosure, a system, particularly a system for characterizing material, comprises: an optical fiber cable positioned in a wellbore drilled through at least one formation; fiber optic cable being configured to receive acoustic signals from an annular material in the wellbore, thereby producing an acoustic response of the annular material; and an optical fiber interrogator optically coupled to the optical fiber cable for characterizing the annular material based on a comparison between the acoustic response as received by the optical fiber cable and at least one acoustic profile of at least one material corresponding reference.
In one or more embodiments of the present disclosure, the annular material comprises at least one drilling fluid, a separating fluid, a slurry of cement and a cement sheath located in an annulus defined by the wellbore, and at least one fluid flowing from the at least one formation to the wellbore.
In one or more embodiment (s) of the present disclosure, the at least one acoustic profile is produced by analyzing the acoustic noise produced by the at least one reference material.
In one or more embodiments of the present disclosure, the noise is produced by at least one of a flow rate, a density, a type, a viscosity and a phase of the present invention. the at least one reference material.
In one or more embodiment (s) of the present disclosure, the at least one acoustic profile is recorded in a database communicatively coupled to the optical fiber interrogator.
In one or more embodiment (s) of the present disclosure, the fiber optic cable is attached to a casing positioned in the wellbore.
In one or more embodiment (s) of the present disclosure, the fiber optic cable is positioned on the outside of the casing.
In one or more embodiment (s) of the present disclosure, the fiber optic cable is positioned within the casing.
In one or more embodiments of the present disclosure, a system, particularly a system for characterizing material, comprises: an acoustic sensor positioned in a wellbore for receiving acoustic signals from an annular material in the wellbore so as to obtain an acoustic response of the annular material by analysis of an acoustic signature of the annular material, and a processor coupled in communication with the acoustic sensor to characterize the annular material on the basis of a comparison between the acoustic response and at least one acoustic profile of at least one corresponding reference material.
In one or more embodiment (s) of the present disclosure, the at least one acoustic profile is produced by analyzing the acoustic noise produced by at least one reference material, and the acoustic noise being produced by at least the flow rate, the density, the type, the viscosity and a phase of the at least one reference material.
In one or more embodiment (s) of the present disclosure, the acoustic sensor comprises a plurality of acoustic sensors positioned in the wellbore at known locations, and a unique identifier is assigned to each acoustic sensor, the unique identifier. correlating to the known location of each acoustic sensor, and a location of the annular material in the wellbore being determined based on the unique identifier.
BRIEF DESCRIPTION OF THE DRAWINGS
The following figures are presented to illustrate certain aspects of the present disclosure, and should not be construed as exclusive embodiments. The subject matter of the invention described may be subject to substantial modifications, alterations, combinations and equivalents in form and function, without departing from the scope of this disclosure.
Figure 1A illustrates an example of a drilling system.
[0008] FIG. 1B illustrates a plan view of an example of a radial arrangement of acoustic sensors of FIG. 1A on the outer surface of the housing.
FIG. 1C illustrates the displacement of the drilling fluid with the placement of a separating fluid and a suspension of cement through the casing in FIG. 1A.
Figure 2 is a graph showing pressure fluctuations detected acoustically over time.
FIG. 3 represents a graph which represents the velocity of the fluid as a function of the square root of the root mean square of the acoustic signal measured under different operating conditions.
Figure 4 is a diagram illustrating a method for determining a type of fluid.
Figure 5A illustrates an example of a wellbore system containing fiber optic sensors.
FIG. 5B illustrates another example of a wellbore system containing optical fiber sensors.
Figure 6 illustrates an example of a processing system for determining a certain type of annular material and / or performing other tasks described herein.
DETAILED DESCRIPTION
The present disclosure relates to the production of hydrocarbons from wellbore and, more particularly, apparatus and a method of identifying fluids behind the casing of a wellbore.
The present disclosure relates to an apparatus and method that does not require RFID or other electronic markings in the fluids present in the annulus to determine the progress of the cement. In fact, the present disclosure relates to passive listening devices that have reduced requirements for electricity consumption. These devices can also access calibration data and compare the measured acoustic response of at least one material in a defined annulus in the wellbore with the calibration data using relatively simple comparison techniques. . Thus, the measurements described herein are relatively easier to obtain compared to measurements obtained from RFID tags and electromagnetic dielectric (EM) spectroscopic measurements.
Referring to FIG. 1A, there is illustrated an exemplary well system 100 which can utilize the principles of the present disclosure. It should be noted that even though FIG. IA is a general example of a terrestrial well system, and experts in the field will readily recognize that the principles described here are equally applicable to subsea operations using floating platforms or installations or on the seabed without departing the scope of this disclosure. A wellbore 108 has been drilled through the various land strata, including the formation 104. While it is shown as vertically extending from the surface 106, in other examples, the wellbore 108 may be deflected, horizontal, or bent over at least portions of the wellbore 108. During a drilling operation, at least one pump 130 (eg, a slurry pump) may circulate fluid 128 through the hole through the inside of a drill pipe and through at least one orifices in the drill bit attached to the distal end of the drill pipe. Pumps 130 may circulate a number of other wellbore compositions (e.g., spacing fluids or cement) into the well during or after the drilling operation, and including a pressure measuring device which gives a pressure reading at the pump outlet. The drilling fluid 128 can then be recycled to the earth's surface 106.
A platform 102 is centered on an underground formation 104 of oil or gas exploitation located below the terrestrial surface 106. The platform 102 includes a working bridge 132 which supports a derrick 134. The derrick 134 supports a device lift 136 for raising and lowering rod trains such as casing 120. When completing the drilling of the wellbore, the drill string and the bit are removed from the wellbore and the casing 120 is lowered into the wellbore. the wellbore 108. The tubing 120 is an interconnected tubular or tubular string extending down the wellbore 108 facilitating the production of oil and gas from the formation 104. Annular space 126 is defined between the casing 120 and the wall of the wellbore 108. A casing shoe 122 is typically attached to the end of the casing string 120 to guide the tubing 120 toward the center of the hole limiting the problems of the casing. associated with striking rocky ridges or water leaks in the wellbore 108 as the casing 120 is lowered down the hole.
Multiple acoustic sensors 138 can be placed at various locations on the outer surface of the casing 120, depending on the design and application requirements. The acoustic sensors 138 may be designed to measure and record the acoustic signature of fluids flowing in the annular space 126. In one embodiment, the acoustic sensors 138 may contain electronic sensors such as hydrophones, piezoelectric sensors , piezo-resistive sensors, electromagnetic sensors, accelerometers or the like. In another embodiment, the acoustic sensors 138 may be fiber optic sensors, such as point sensors (eg, fiber Bragg gratings, etc.) distributed at desired or predefined locations along the pathway. length of an optical fiber. In yet another embodiment, the acoustic sensors 138 may be distributed acoustic sensors, which may also use the optical fibers and allow distributed measurement of local acoustic parameters at any given point along the fiber. In these embodiments, the optical fiber may be attached to the tubing 120 or otherwise transported into the wellbore 108 by the cable (not specifically illustrated). In yet another embodiment, the acoustic sensors 138 may contain accelerometers or optical hydrophones with fiber optic cabling.
The placement of acoustic sensors 138 can be based on the design and application of the sensors. Fig. 1B, for example, illustrates a plan view of an exemplary radial arrangement of acoustic sensors 138 on the outer surface of the casing 120. The radial arrangement comprises four acoustic sensors 138 positioned at about eighty -dix degrees relative to each other to the outer radial surface 121 of the casing 120. Accordingly, each acoustic sensor 138 can acquire independent flow sounds at different angular locations. This case may be beneficial in cases of large deviation or even horizontal wells, where a relatively heavy fluid may flow near the bottom of the casing while lighter fluid may flow near the top. The arrangement of sensors is thus sensitive to azimuthally unsymmetrical flows. It will be understood that the type of sensor, the placement of the acoustic sensors and the number of acoustic sensors 138 is merely an example, and these may vary as needed.
In the case of optical fiber sensors, a number of distributed optical fiber sensing methodologies may be used to determine the desired fluid in the annular space 126, without departing from the scope of the present disclosure. Typically, an optical fiber comprising point sensors or used as a distributed acoustic sensor is optically coupled to (i.e., in optical communication with) a narrow band electromagnetic radiation source, such as a band laser. The laser may be used to produce short pulses of light which are released into the optical fiber, and a fraction of the backscattered light which falls into the angular acceptance cone in the backward direction. . ~ to d. towards the laser source, can be guided back to the launch end of the fiber in the form of a backscattered signal.
The backscattered signal may come from impurities in the fiber, areas of different refractive indexes in the fiber produced during fiber manufacture, interactions with the surfaces of the optical fiber and / or connections. between the fiber and other fibers or optical components. Part of the backscattered electromagnetic radiation is treated as unwanted noise, and steps can be taken to reduce this backscattering. The backscattered return signal can be used to obtain information about the state of time variation of the stress along the optical fiber, which can be equated where the fluctuations in noise (vibrations) occur. A detector, such as an optoelectronic device, may be in optical communication with the optical fiber and serve to convert the backscattered electromagnetic signals into electrical signals, and a signal processor may process the electrical signals to determine the magnitude of the strain undergone by the optical fiber downstream of the detector.
[0024] Two measurement principles for distributed sensing technology are the Backscatter Method (OTDR) and the Frequency Domain Reflectometry (OFDR). The OTDR detects and analyzes coherent Rayleigh backscatter signals produced from narrow laser pulses generated by a laser, sent into the optical fiber. Depending on the time required for the backscattered light to return to an associated detector, it is possible to locate the location of a variation in the characteristics of the optical fiber. The OFDR provides information on the local characteristic only when the backscattered signal detected throughout the duration of the measurement is frequency-dependent in a complex manner and then Fourier-transformed. The essential principles of OFDR technology are the near-continuous wave mode used by the laser and the narrow-band detection of the backscattered optical signal.
Figure 1C is an enlarged schematic view of a portion of the well system 100 of FIG. 1 A. After drilling the wellbore 108, the tubing 120 is introduced into the wellbore 108, which may still be completely or partially filled with drilling fluid 128. The tubing 120 may then be attached into the wellbore 108 by pumping a cement slurry 142 down through the tubing 120 and into the annular space 126, as indicated generally by the arrows of FIG. For this, the drilling fluid 128 can be moved from the wellbore 108 by means of a separating fluid 140 and a suspension of cement 142. In other embodiments, the separation fluid 140 can be a process fluid containing oven dust and water, but otherwise, it may contain other fluids such as fresh water, salt water or other non-expensive fluid. The separation fluid 140 may be pumped into the casing 120 and thereby hydraulically force the drilling fluid 128 out of the casing 120 and into the annular space 126 through the casing shoe 122. Forcing the drilling fluid 128 in the annular space 126 eliminates the dehydrated / gelled drilling fluid and / or the filter cake solids from the wellbore 108 in advance of the cement suspension 142.
As can be seen, the separation fluid 140 can also separate the drilling fluid 128 from the cement suspension 142. The cement suspension 142 can be introduced into the casing 120 behind the separation fluid 140 and can be removed. flow to the bottom of casing 120 and to the top of annular space 126 to form the cement sheath which secures casing 120 to wellbore 108.
While the drilling fluid 128, the separation fluid 140 and the cement suspension 142 flow into the annular space 126, the dynamic pressure of the flow can cause small pressure fluctuations that can be monitored. thanks to the acoustic sensors 138. The dynamic pressure can be several orders of magnitude lower than the static pressure in the absence of flow. The dynamic pressure ΔΡ is related to the acoustic noise produced by the fluid flow and is measurable. Specifically, the dynamic pressure ΔΡ is proportional to the root mean square of the acoustic signal -v in the form ÛP K.
For the flow of water, the dynamic pressure is related to the speed of the fluid in a pipe by the relation
, where P is the density of the fluid and where u is the average fluid flow velocity. For fluids other than water, the functional form
can be a relatively complex expression related to the dynamic pressure with respect to density, fluid velocity and viscosity, and can be generally represented in the form of
This expression can be obtained with laboratory results and / or can be represented as an equation or a lookup table.
Any flow of fluid in the annular space 126 during the placement of the cement suspension, hardening of the cement and the service life of the well can be determined according to the foregoing analysis. During placement of the cement slurry for example, the drilling fluid 128, the separating fluid 140 and the cement slurry 142 in the annular space 126 must each emit a unique acoustic signature that is detected by the acoustic sensors 138. Depending on the acoustic signature detected, the location of the drilling fluid 128, the separating fluid 140 and the cement suspension 142 in the annular space 126 are determined.
During curing, the cement suspension 142 passes from a liquid cement sheath to solid. During the transition, the viscosity of the cement suspension 142 varies over time, and this results in a variation of the acoustic signature of the cement suspension 142. The monitoring of the cement suspension 142 signature when it passes from the The solid state liquid state can help determine the timing of the following operations in the well, such as drilling, completions, production, etc.
The cement sheath in the annular space 126 may produce cracks during the service life of the well. This may be due to expansion and contraction of the casing or to wellbore operations. During cracking, a cracking noise with a distinct acoustic signature is produced by the cement sheath. The acoustic sensors 138 detect the acoustic signature from the cracking noise and the location of the crack in the cement sheath can be determined. Flow paths may occur in the cracked cement sheath and / or in the annular micro-space. Any flow of fluid in the flow paths will have a unique acoustic signature that is detected by the acoustic sensors 138. According to the unique acoustic signature, the location of the flow path and the crack in the cement sheath. The acoustic signature can also be used to determine the creation of any annular micro-space.
In well abandonment procedures, any production zone in the well can be identified from the acoustic signatures and sealed. All communicating areas are identified and processed. Depending on the acoustic signatures, it is possible to determine the nature of any fluid entering the annulus 126 from the formation 104. The incoming fluid causes a variation of the acoustic signatures, indicating the location of the fluid leak. Repair tasks can then be performed to prevent the influx of fluid from the formation 104.
It will therefore be understood that the acoustic responses of any material located in the annular space 126 (also called an annular material) can be monitored according to the embodiments described herein. In some embodiments, the annular material may be the drilling fluid 128, the separation fluid 140, and the cement suspension 142. In other embodiments, the annulus material may comprise the cement suspension in various stages of the liquid to gel-to-solid phase transition as the cement slurry 142 cures in the annulus 126. In yet other embodiments, the annulus material may comprise the solid cement sheath in the annular space 126. In still other embodiments, the annulus material may comprise a cracked or deformed cement sheath having at least one flow path. In at least one embodiment, the annular material may be any formation fluid. In at least one further embodiment, the annular space material may comprise the fluid (including gas) flowing from the formation 104 to the wellbore 108. The acoustic sensors 138 detect the acoustic signature of that wellbore. fluid near the wellbore 108, and thus determine whether a fluid has reached an area near the wellbore 108 that is not expected during the service life of the well. This can prevent the production of undesirable fluids through the remediation and / or closure of perforations. This is possible by intervention or by an automatic process, or by a combination of these.
Figure 2 is a graph 200 showing the acoustically detected pressure fluctuations 202 over time. Line 202 represents time dependent pressure. The time-dependent pressure must fluctuate due to vortices produced in the flowing fluid. We can determine a median pressure
, and it appears as line 204. The dynamic pressure can be determined as a function of
. In measure 206, ÆMS (y) ni (pque) has root mean square of the dynamic pressure ÛP.
The average of the dynamic pressure & P may be zero, while the root mean square of the pressure fluctuations may not be. If the relationship
between the dynamic pressure or equivalently RMS (y) and the fluidic parameters and the fluid velocity is known, then the fluid density must be computable either analytically or computerically from the other parameters of the equation.
According to an illustrative example, a fluid is considered which follows the same relationship as for water, with
. If the flow is known, for example if the flow is measured during penetration into the wellbore or controlled by the surface equipment, the density of the fluid can be estimated as
, Equation 1, where A is a proportionality constant, u is the known flow rate, P is the fluid density, and RMS is the root mean square of the measured acoustic signal. The proportionality constant K may depend on the type of fluid and the mechanical characteristics of the well, which can be determined by a calibration procedure using fluids of known density. For more complex expression fluids related to dynamic pressure with respect to flow velocity, density and viscosity, etc., density can be estimated analytically or computerically. Note that equation 1 is simply an example and that the relation can be expressed according to other equations as well.
For equation 1, if it is considered that the fluid velocities are the same at a particular point in the annular space 126 and the viscosity of the different fluids is the same, then the relative density of the different fluids can be measured Under the form
, Equation 2 where P-Ps represent the density values of a first fluid and a second fluid, respectively, and where PM5 (> 1)} RM5 (- -) represent the quadratic averages of the acoustic signals measured from the first fluid and the second fluid, respectively. An increase in viscosity results in a reduction of acoustic fluctuations or wideband sound power. These responses can be calibrated in a laboratory for useful fluids relative to representative fluid velocities. FIG. 3 represents a graph 300 which represents the velocity of the fluid as a function of the square root of the root mean square of the acoustic signal measured under different operating conditions. At graph 300, the acoustic signal is graphically plotted against changes in fluid flow, as indicated by the points in sample 304. As can be seen, the equal distribution of the sample points on the part and the Another line 302 indicates a linearly variable relationship between the fluid flow and the acoustic signal.
Figure 4 is a flowchart illustrating a method 400 for determining a type of annular material. As seen, the method 400 contains a first step 401 and a second step 403. The first step 401 involves a calibration process of the acoustic sensors 138 (see Fig. 1A). In this context, the acoustic sensors 138 may be at least one of the electronic detectors described above. The first step 401 can take place before the cementing operation, in a laboratory before installing the acoustic sensors 138 in the wellbore 108 (see Figure IC) or it can take place during the introduction of the casing. The second step 403 involves identifying and otherwise characterizing the type of annular material during and after the cementing operation.
In step 401, the acoustic noise produced by at least one reference material is measured, as in 402. In some embodiments, the reference materials may be the drilling fluid 128 see Figure IC) the separation fluid 140 (see Fig. 1C) and the cement suspension 142 (see Fig. 1C). In other embodiments, the reference materials may comprise the cement slurry in various phases as it passes from the liquid state to the solid state. In yet other embodiments, the reference material may be a solidified cement sheath. In yet other embodiments, the reference materials may include fluids that may flow from the formation 104 to the wellbore 108 (e.g., fluids flowing in the annulus 126) during the service life of the well. It will thus be understood that the reference materials are not limited to the abovementioned materials and that they may comprise any annular material which is introduced or formed in the annular space 126 defined in the wellbore 108. The measured acoustic noise can then be characterized, as in 404. More particularly, each material produces a distinct acoustic noise which depends on the flow rate, density, type, viscosity and phase of the material. During characterization, analytical expressions (eg, equations 1 and 2 above) or lookup tables are used to correlate the type of reference material and at least one experimentally measured parameter (eg, sound power) can be extracted using standard data analysis techniques, machine learning or optimization algorithms such as genetic algorithms. The results of the characterization of an acoustic profile are obtained for a desired duration for each reference material, as in 406. Each acoustic profile may represent a variation of the at least one parameter measured for a desired duration. At least one criterion of flow, density, viscosity and phase of the reference materials may be varied to produce different acoustic profiles of the same reference material. The acoustic profiles can be recorded (for example in a look-up table) in a non-volatile memory of each acoustic sensor 138, as in 408. Otherwise, the acoustic profiles can be recorded in a surface position, for example in a base of data located at a central computer facility. In some embodiments, the analytical expressions (e.g., equations 1 or 2 above) used to create the different acoustic profiles may be recorded and the different acoustic profiles may be generated in real time during operation. For the sake of clarity, it is considered that three profiles PI, P2 and P3 are produced in the calibration step 401. However, it will be understood that the number of acoustic profiles produced may be greater than or less than three.
In the second step 403, at least one annular material may be characterized (or identified) during or after a cementing operation. The second step 403 may also involve the characterization of at least one annular material during the service life of the well. The at least one annular material may contain the drilling fluid 128, the separation fluid 140, the cement suspension 142, the cement suspension 142 in various phases as it passes from the liquid state to the solid state and the solid cement sheath. During the cementing operation, the acoustic sensors 138 record the acoustic signatures of the annular materials flowing through the annular space 126, as at 410. In one example, the acoustic sensors 138 can record the acoustic signatures over a time window. predefined (eg 1 to 2 min). At least one processor communicatively coupled to each acoustic sensor 138 analyzes the recorded acoustic signatures, such as at 412. The at least one processor may be located in each acoustic sensor 138, or located at a surface location. The analysis may include frequency content analysis from fast Fourier transform (FFT), power spectral analysis or the like. The at least one processor produces an acoustic response based on the analysis, as in 414.
The acoustic response can first be compared or otherwise adapted to the acoustic profiles, as in 416, 420 and 424. In some embodiments, for example, the acoustic response can be compared successively to the acoustic profiles. As a result, the acoustic response is first compared to the acoustic profile PI, as in 416. If the acoustic response corresponds to the acoustic profile PI, the annular material is identified as the first reference material (corresponding to the acoustic profile PI), as in 418, and the result is recorded in the memory of the acoustic sensor 138, as in 428. The result can be retrieved later using an intervention tool. Otherwise, at 428, the result can be communicated in real time to the surface 106 by means of a set of telecommunication means such as, but not limited to, electromagnetic telemetry, acoustic telemetry, fiber optic telemetry, signals by son or without son, or any combination thereof.
If the acoustic response does not correspond to the acoustic profile PI, the acoustic response can then be compared to the acoustic profile P2, as in 420. If the acoustic response corresponds to the acoustic profile P2, the annular material is identified as the second material. reference (corresponding to the acoustic profile P2), as in 422, and the result is recorded in the onboard memory of the acoustic sensor 138, as in 428. Otherwise, as indicated above, the result can be communicated in real time to the surface. 106 through at least one telecommunication method.
If the acoustic response does not correspond to the acoustic profile P2, the acoustic response can then be compared to the acoustic profile P3, as in 424. If the acoustic response corresponds to the acoustic profile P3, the annular material is identified as the third material. reference (corresponding to the acoustic profile P3), as in 426, and the result is recorded in the onboard memory of the acoustic sensor 138, as in 428. Otherwise, the result can be communicated in real time to the surface 106 thanks to the least one telecommunication method, as already indicated. The method 400 is then repeated, as in 430, where the acoustic sensors 138 can record the acoustic signatures of fluids flowing in the annular space 126 in the following time window.
A unique identifier is assigned to each acoustic sensor 138, and is related to the position (depth) of each acoustic sensor 138 in the annular space 126. Thus, the location of the different annular materials identified in the space ring 126 may be induced by the unique identifier.
It will be readily understood that the number of annular materials and types of annular materials mentioned above are only examples, and these are not limited to these examples. For example, acoustic sensors 138 may be calibrated while profiles and other materials, such as hydrocarbons, oils, water (fresh or salt), cleaning fluids, chemical washings, or Similar. In addition, the number of materials can be increased or reduced as needed.
In one example, the acoustic sensors 138 can record the acoustic signature of a mixed flow during a time window. A mixed flow may be a mixture of two or more types of materials. Thus, the response produced from such a mixed flow must not correspond to any of the acoustic profiles. Since the acoustic signature depends on the flow rate of the annular material, the different flow rates can be extracted from the acoustic response. The rates can be extracted by one of the processors within the acoustic sensors 138, or the rates can be transmitted at a surface point for processing. Depending on the flow rates, the type of annular materials can be determined in the mixed flow. [0046] Figure 5A illustrates an example of wellbore system 500 containing fiber optic sensors. The system 500 may contain a wellbore 502 that enters a subterranean formation 504. The wellbore 502 may be drilled into the subterranean formation 504, using any suitable drilling technique. Although illustrated as extending vertically from surface 506 in FIG. 5A, in other examples, wellbore 502 can be deflected, horizontal or curved on at least some portions of wellbore 502. The wellbore 502 may include a surface casing 508, a production casing 510 and a tubing 512. Parts of the wellbore 502 may otherwise be out casing or "open well". The piping 512 may extend from the surface 506 into an interior area defined by the production tubing 510. The tubing 512 may be the production tubing through which the hydrocarbons or other fluid may enter or be routed through the tubing. surface 506.
Although not illustrated for the sake of clarity, the well system 500 may comprise a service platform, for example a drilling platform, a completion platform, a repackaging platform, another mast structure or a combination of them. In some aspects, the service platform may include a work deck that supports a derrick. In underwater operations, jetties extending down to a seabed in some implementations may support the service platform. Alternatively, the service platform may be supported by columns resting on hulls or on pontoons (or both) that are ballasted below the surface of the water, which may be called a semi-submersible platform or platform anyway. In an offshore location, a riser may extend from the service platform to exclude seawater and contain drilling fluid returns. One can also find a wellhead at the top of the well on the surface. Other mechanical mechanisms that are not visible can control the introduction and removal of a work train in the wellbore 502. Among the examples of such mechanical mechanisms, there is a traction structure coupled to a control unit. lifting, a smooth cable unit or a cable line unit comprising a hoist, another service vehicle and a coiled tubing unit.
The wellbore system 500 contains an optical fiber acoustic detection subsystem that can detect noise or other vibrations in the wellbore 502, for example during a cementing operation. The optical fiber acoustic detection subsystem comprises an optical fiber interrogator 516 located at the surface 506 and at least one fiber optic cable 514 communicatively coupled to the optical fiber interrogator 516. The fiber optic cables 514 may comprise multiple sensors, such as point sensors located in different areas of the wellbore 502, or may otherwise operate as a distributed acoustic sensing cable. The fiber optic cables 514 may be on a recoverable cable line 518. The fiber optic cables 514 may contain single mode optical fibers, multiple mode optical fibers or multiple fibers of multiple fiber types. The optical fiber cables 514 may each contain at least one single mode fiber, at least one multimode fiber, or a combination thereof.
The interaction of the optical fiber cable 514 with the noise or with other vibrations coming from the wellbore 502 produces a stress in the optical fiber cable 514. During operation, the optical fiber interrogator 516 injects a highly coherent light beam, such as a laser pulse, in the fiber optic cable 514. The strain variation in the fiber optic cable 514 causes an optical path difference transmitted by the optical fiber interrogator 516. Path difference induces optical phase variation in the backscattered light. The phase variation is detected by the optical fiber interrogator 516 according to various interferometry techniques to determine the location of the stress and thus the location of the annular material in the wellbore 106.
FIG. 5B illustrates another example of a wellbore system 600 containing optical fiber sensors. The wellbore system 600 may be similar in some aspects to the wellbore system 500 of FIG. 5A and therefore can best be understood by reference, while like numbers represent like components which will no longer be described in detail. Unlike the wellbore system 500, at least one fiber optic cable 514 (one shown) is outside the production tubing 510. As can be seen, the fiber optic cable 514 may be coupled to the 512. In some embodiments, the tubing clamps 513 are coupling transverse protectors located at both joints of the tubing 512. The operation of the wellbore system 600 is similar to that of the wellbore system 500 described above, and it is not repeated here for the sake of brevity.
Figure 6 illustrates an example of a processing system 700 for determining a certain type of annular material. The system 700 can for example process data from at least one of the sensors 138 in FIGS. 1A-1C, configure and / or control the optical fiber interrogator 516 in FIGS. 5A and 5B, can implement the method 400 described. previously, or perform other tasks described here.
The system 700 may comprise a processor 710, a memory 720, a recording device 730 and an input / output device 740. Each of the components 710, 720, 730 and 740 may be interconnected, for example with a bus of 750. The processor 710 may process instructions to be executed within the system 700. In some embodiments, the processor 710 is a single-file processor, a multiple-file processor, or another type of processor. . The processor 710 can process processing instructions stored in the memory 720 or on the recording device 730. The memory 720 and the recording device 730 can record information within the computer system 700.
The input / output device 740 allows input / output operations for the system 700. In some embodiments, the input / output device 740 may include at least one network interface device. eg an Ethernet card; a serial communication device, e.g. an RS-232 port; and / or a wireless interface device, eg, an 802.11 card, a 3G wireless modem, or a 4G wireless modem. In some embodiments, the input / output device may include pilot devices adapted to receive input data and to output data to other input / output devices, eg, a keyboard 760. In some embodiments, mobile computing devices, mobile telecommunication devices, and other devices may be used.
In accordance with at least some embodiments, the disclosed methods and systems related to scanning and analyzing hardware may be implemented in a digital electronic circuit, or in computer software, firmware, or hardware, comprising the structures described in this specification and their structural equivalents, or combinations of one or more of these. Computer software may include, for example, one or more instruction modules, encoded on a computer readable recording medium to be executed by, or to control the operation of, a data processing device. Examples of a computer-readable recording device include random access memory (RAM) devices, read-only memory (ROM) devices, optical devices (eg, CD or DVD), and disk drives.
The term "data processing device" encompasses all types of devices, devices and machines for data processing, including, as an example, a programmable processor, a computer, a system on a chip, or multiple chips, or combinations thereof. The device may include a dedicated logic circuit, eg, an FPGA (programmable gate IC) or an ASIC (application specific integrated circuit). The apparatuses may also include, in addition to the hardware, code that creates a runtime environment for the computer program in question, eg, code that constitutes the processor firmware, a protocol stack, a management system, and databases, a database management system, an operating system, a multiplatform run time environment, a virtual machine, or a combination of one or more of these. The apparatus and the runtime environment can realize different computer model infrastructures, such as web services and distributed and grid computing infrastructures.
A computer program (also called program, software, software application, script or code) may be written in any form of programming language, including compiled or interpreted languages, declarations or procedural languages. A computer program may, but not necessarily, correspond to a file of a file system. A program can be saved to a part of a file that contains other programs or data (eg, one or more scripts saved in a markup language document), a single file dedicated to the program in question, or multiple Coordinated files (eg, files that contain one or more modules, subroutines, or portions of code). A computer program may be run on a computer or multiple computers that are located at a site or at multiple sites dispersed and interconnected by a telecommunication network. [0057] Some of the processes and logical flows described in this specification may performed by one or more programmable processors executing one or more computer programs to generate actions by processing input data and generating output. Processes and logical flows can also be performed by, and the device can also be implemented as special function logic circuits, eg FPGA (programmable gate IC) or ASIC (application specific integrated circuit).
Suitable processors for running a computer program include, as an example, both microprocessors and versatile and specialized processors of any type of digital computer. In general, a processor will receive instructions and data from a ROM or RAM, or both. A computer includes a processor for performing actions in accordance with instructions and one or more memory devices for recording instructions and data. A computer may also include, or may be operably coupled to receive data from, one or more mass storage devices for recording data or for transferring data thereto, or both, by magnetic discs, magneto-optical discs or optical discs. However, a computer may not have these devices. Suitable devices for storing instructions and data from a computer program include all forms of nonvolatile memory, media and memory devices, including, for example, semiconductor memory devices (e.g., EPROM, EEPROM , flash memory devices, and others), magnetic disks (e.g., internal hard disks, removable disks, and the like), magneto-optical disks, and CD-ROMs and DVD-ROMs. The processor and the memory may be supplemented by, or incorporated into, a dedicated logic circuit.
In order to provide interaction with a user, the operations may be implemented on a computer having a display device (eg, a screen or other type of display device) to display information to the user. and a keyboard and pointing device (eg, a mouse, trackball, tablet, touch screen, or other type of pointing device) by which the user can enter data into the computer. Other types of devices may also be used to interact with a user; for example, feedback to the user may be in the form of any sensory feedback, eg, visual feedback, acoustic feedback, or tactile feedback; and user input can be received in any form, including acoustic, voice or tactile input. In addition, a computer may interact with a user by sending documents to and receiving documents from a device that is used by the user; eg, sending web pages to a browser or client device of the user in response to requests from the web browser.
[0060] A computer system may comprise a single computer device, or multiple computers that operate near or generally at a distance from one another and generally communicate through a telecommunication network. Examples of communication networks include a local area network ("LAN") and a wide area network ("WAN"), an inter-network (eg, the Internet), a network comprising a satellite link and local area networks. post office (eg ad hoc peer-to-peer networks). A client and server relationship can be generated by computer programs that are run on the respective computers and have a client / server relationship to each other.
Embodiments described herein include: [0062] A: A method comprising measuring an acoustic noise generated by at least one reference material and producing at least one corresponding acoustic profile, monitoring a material annulus in a wellbore drilled through at least one formation with at least one acoustic sensor positioned in the wellbore so as to obtain an acoustic response of the annular material, comparing the acoustic response with at least one acoustic profile using a processor coupled in communication with at least one acoustic sensor, and the characterization of the annular material based on the comparison of the acoustic response with the at least one acoustic profile.
B: A system that includes an optical fiber cable positioned in a wellbore drilled through at least one formation, the fiber optic cable being configured to receive acoustic signals of an annular material in the wellbore to provide an acoustic response of the annular material, and an optical fiber interrogator optically coupled to the optical fiber cable for characterizing the annular material based on a comparison of the acoustic response as received by the fiber optic cable. and at least one acoustic profile of at least one corresponding reference material.
C: A system which comprises an acoustic sensor positioned in a wellbore for receiving acoustic signals of an annular material in the wellbore so as to obtain an acoustic response of the annular material by analysis of an acoustic signature annular material, and a processor coupled in communication with the acoustic sensor for characterizing the annular material based on a comparison between the acoustic response and at least one acoustic profile of at least one corresponding reference material.
Each of Embodiments A, B and C may have one or more of the following additional elements, in any combination: Element 1: Monitoring the annular material in the wellbore includes monitoring at least one of a drilling fluid, a separating fluid, a suspension of cement and a cement sheath located in an annular space defined by the wellbore, and at least one fluid which flows from the at least one formation to the wellbore. Element 2: The measurement of the acoustic noise produced by the at least one reference material includes the measurement of the acoustic noise produced as a function of at least one of a flow rate, a density, a type, a a viscosity and a phase of the at least one reference material. Element 3: Obtaining the acoustic response of the annular material comprises analyzing an acoustic noise signature of the annular material in the wellbore to obtain the acoustic response. Element 4: the acoustic sensor comprises an array of electronic sensors and the monitoring of the annular material with the at least one acoustic sensor comprises obtaining the acoustic response of the annular material using the matrix of electronic sensors. Element 5: furthermore comprises obtaining the acoustic response of the annular material during a predefined time window. Element 6: Characterization of the annular material comprises characterization of a type of annular material, and the method further comprises transmitting the annular material type in real time at a surface location, and / or recording of the annular material type in the acoustic sensor. Element 7: The acoustic sensor comprises a plurality of acoustic sensors positioned in the wellbore at known locations and the method further comprises assigning a unique identifier to each acoustic sensor of the plurality of acoustic sensors, the identifier unique being correlated to the known location of each acoustic sensor, and determining a location of the annular material in the wellbore based on the unique identifier. Element 8: The at least one acoustic profile is recorded in a memory device included in the acoustic sensor. Element 9: the at least one acoustic profile is recorded at a surface position. Element 10: The processor is in the wellbore. Element 11: The processor is in a surface position. Element 12: the annular material comprises at least one drilling fluid, a separating fluid, a suspension of cement and a cement sheath located in an annular space defined by the wellbore, and at least one fluid flowing from the at least one formation to the wellbore. Element 13: the at least one acoustic profile is produced by analyzing the acoustic noise produced by the at least one reference material. Element 14: The noise is produced by at least one of a flow rate, a density, a type, a viscosity and a phase of the at least one reference material. Element 15: the at least one acoustic profile is recorded in a database communicatively coupled to the optical fiber interrogator. Element 16: The fiber optic cable is attached to a casing positioned in the wellbore. Element 17: The fiber optic cable is positioned on the outside of the casing. Element 18: The fiber optic cable is positioned inside the casing. Element 19: The fiber optic cable is led to the wellbore by a cable line.
Element 20: the at least one acoustic profile is produced by analyzing the acoustic noise produced by at least one reference material, and the acoustic noise is produced by at least one of a flow, a density , a type, a viscosity and a phase of the at least one reference material. Element 21: the acoustic sensor comprises a plurality of acoustic sensors positioned in the wellbore at known locations, and a unique identifier is assigned to each acoustic sensor, the unique identifier being correlated to the known location of each acoustic sensor, and a location of the annular material in the wellbore is determined according to the unique identifier.
As a nonlimiting example, examples of combinations applicable to A, B and C comprise: element 13 with element 14; element 13 with element 15; element 16 with element 17; and element 16 with element 18.
Thus, the disclosed systems and methods are well suited to achieve the stated purposes and advantages, as well as those inherent thereto. The particular embodiments described above are illustrative only, and the teachings of the present disclosure may be modified and practiced in different but equivalent ways that will be apparent to those skilled in the art who benefit from these teachings. In addition, no limitation is provided to the construction or design details disclosed herein, other than those described in the claims below. It is therefore obvious that the particular illustrative embodiments described above may be altered, combined or modified and that all such variations are considered within the scope of the present disclosure. The systems and methods described illustratively herein can be conveniently practiced in the absence of any element not specifically described herein and / or any optional element described herein. Although the compositions and methods are described herein in terms of "comprising", "containing" or "including" various components or steps, the compositions and methods may also "consist essentially of" or "consist of" various components and steps. All figures and intervals disclosed above may vary by a certain amount. When a numerical range with a lower and upper limit is indicated, any number and range within the range are specifically indicated. In particular, each range of values (of the form, "from about a to about b" or, equivalently, "from about a to b", or, equivalently, "from about ab") indicated here should be understood as describing each number and interval within the widest range of values. But also, the terms in the claims have a clear and ordinary meaning, except in case of explicit and clear indication other defined by the applicant. In addition, the undefined articles "a" or "an" used in claims as defined herein means one or more of the elements they introduce.
In this context, the expression "at least one" preceding a series of articles, with the words "and" or "or" to separate any of the articles, modifies the list as everything, rather each member of the list (ie, each article). The term "at least one" means a meaning that includes at least one of the articles and / or at least one of any combination of the articles and / or at least one of each of the articles. As an example, the sentences "at least one of A, B and C" or "at least one of A, B or C" describe only A, only B or only C; any combination of A, B and C and / or at least one of each of A, B and C.
The use of directional terms such as above, below, above, below, up, down, left, right, at the top of the hole, down the hole, etc., are used in connection with the illustrative embodiments as illustrated in the figures, the upward direction being upwardly of the corresponding figure and the downward direction being downward of the corresponding figure, the direction towards the the top of the hole being towards the surface of the well and the downward direction of the hole being towards the well's hoof.

权利要求:
Claims (19)
[1" id="c-fr-0001]
A method (400) for characterizing material, characterized in that said method (400) comprises: measuring acoustic noise produced by at least one reference material so as to produce at least one acoustic profile (PI, P2, P3) corresponding; monitoring an annular material in a wellbore (108, 502) drilled through at least one formation (104, 504) with at least one acoustic sensor (138) positioned in the wellbore (108, 502), in order to obtain an acoustic response of the annular material; comparing the acoustic response with Pau minus an acoustic profile (PI, P2, P3) using a processor (710) coupled in communication with Pau minus an acoustic sensor (138); and characterizing the annular material based on the comparison of the acoustic response and Pau minus an acoustic profile (PI, P2, P3).
[2" id="c-fr-0002]
The method (400) of claim 1 wherein monitoring annular material in the wellbore (108, 502) includes monitoring at least one of a drilling fluid (128), a fluid separator (140), a cement slurry (142) and a cement sheath located in an annular space (126) defined by the wellbore (108, 502), and at least one fluid which flows from Pau less a formation (104, 504) to the wellbore (108, 502).
[3" id="c-fr-0003]
The method (400) according to claim 1 or 2, wherein the measurement of the acoustic noise produced by Pau minus a reference material comprises measuring the acoustic noise produced as a function of at least one of a flow rate, d a density, a type, a viscosity and a phase of the at least one reference material.
[4" id="c-fr-0004]
The method (400) according to any one of claims 1 to 3, wherein obtaining the acoustic response of the annular material comprises analyzing an acoustic noise signature of the annular material in the wellbore (108). , 502) to obtain the acoustic response.
[5" id="c-fr-0005]
The method (400) according to any one of claims 1 to 4, wherein the acoustic sensor (138) comprises an array of electronic sensors and wherein monitoring the annular material with the at least one acoustic sensor (138) comprises obtaining the acoustic response of the annular material using the matrix of electronic sensors.
[6" id="c-fr-0006]
The method (400) according to any one of claims 1 to 5, wherein the characterization of the annular material comprises the characterization of a type of annular material, and wherein the method further comprises transmitting the annular material type. in real time at a surface location and / or recording the type of annular material in the acoustic sensor (138).
[7" id="c-fr-0007]
The method (400) according to any one of claims 1 to 6, wherein the acoustic sensor (138) comprises a plurality of acoustic sensors (138) positioned in the wellbore (108, 502) at known locations, and the method (400) further comprising: assigning a unique identifier to each acoustic sensor (138) of the plurality of acoustic sensors (138), the unique identifier being correlated to the known location of each acoustic sensor (138), and determining a location of the annular material in the wellbore (108, 502) based on the unique identifier.
[8" id="c-fr-0008]
The method (400) according to any one of claims 1 to 7, wherein the at least one acoustic profile (PI, P2, P3) is recorded at a surface location and / or in a storage device. memory included in the acoustic sensor (138).
[9" id="c-fr-0009]
The method (400) of any one of claims 1 to 8, wherein the processor (710) is in a surface position or in the wellbore (108, 502).
[10" id="c-fr-0010]
A system for characterizing material, characterized in that said system comprises: an optical fiber cable (514) positioned in a wellbore (108, 502) drilled through at least one formation (104, 504), the an optical fiber cable (514) configured to receive acoustic signals from an annular material in the wellbore (108, 502) to provide an acoustic response of the annular material; and an optical fiber interrogator (516) optically coupled to the optical fiber cable (514) for characterizing the annular material based on a comparison between the acoustic response as received by the fiber optic cable (514) and at least one an acoustic profile (PI, P2, P3) of at least one corresponding reference material.
[11" id="c-fr-0011]
The system of claim 10, wherein the fiber optic cable (514) is attached to a casing (120, 510) positioned in the wellbore (108, 502).
[12" id="c-fr-0012]
The system of claim 11, wherein the fiber optic cable (514) is positioned on the outside of the casing (120, 510).
[13" id="c-fr-0013]
The system of claim 11, wherein the fiber optic cable (514) is positioned within the casing (120, 510).
[14" id="c-fr-0014]
The system according to any one of claims 10 to 13, wherein the at least one acoustic profile (PI, P2, P3) is recorded in a database communicatively coupled to the optical fiber interrogator (516). .
[15" id="c-fr-0015]
A system for characterizing material, characterized in that said system comprises: an acoustic sensor (138) positioned in a wellbore (108, 502) for receiving acoustic signals from an annular material in the wellbore ( 108, 502) so as to obtain an acoustic response of the annular material by an analysis of an acoustic signature of the annular material, and a processor (710) communicatively coupled to the acoustic sensor (138) for characterizing the annular material on the basis of a comparison between the acoustic response and at least one acoustic profile (PI, P2, P3) of at least one corresponding reference material.
[16" id="c-fr-0016]
The system of claim 15, wherein the acoustic sensor (138) comprises a plurality of acoustic sensors (138) positioned in the wellbore (108, 502) at known locations, and a unique identifier assigned to each sensor. acoustically (138), the unique identifier being correlated to the known location of each acoustic sensor (138), and a location of the annular material in the wellbore (108, 502) being determined according to the unique identifier.
[17" id="c-fr-0017]
The system of any one of claims 10 to 16, wherein the annular material comprises at least one of a drilling fluid (128), a separation fluid (140), a suspension of cement (142) and a cement sheath located in an annular space (126) defined by the wellbore (108, 502), and at least one fluid that flows from at least one formation (104, 504) to the wellbore (108, 502).
[18" id="c-fr-0018]
18. System according to any one of claims 10 to 17, wherein the at least one acoustic profile (PI, P2, P3) is produced by analyzing the acoustic noise produced by the at least one reference material.
[19" id="c-fr-0019]
The system of claim 18, wherein the noise is produced by at least one of a flow rate, a density, a type, a viscosity and a phase of the at least one material. reference.

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公开号 | 公开日

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GB2557030B|2021-07-21|

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US20180238167A1|2018-08-23|

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NO20180055A1|2018-01-12|

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法律状态:
2017-07-26| PLFP| Fee payment|Year of fee payment: 2 |

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2018-07-18| PLFP| Fee payment|Year of fee payment: 3 |

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2018-10-26| PLSC| Search report ready|Effective date: 20181026 |

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2019-07-30| PLFP| Fee payment|Year of fee payment: 4 |

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2021-04-09| ST| Notification of lapse|Effective date: 20210305 |

优先权:

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申请号 | 申请日 | 专利标题

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USWOUS2015046877|2015-08-26|

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PCT/US2015/046877|WO2017034558A1|2015-08-26|2015-08-26|Method and apparatus for identifying fluids behind casing|

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