Patent Publication Number: US-11035229-B2

Title: Segmented wireless production logging

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a divisional of U.S. patent application Ser. No. 15/236,566, filed Aug. 15, 2016, titled “SEGMENTED WIRELESS PRODUCTION LOGGING,” the full disclosure of which is hereby incorporated herein by reference in its entirety for all purposes. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of Invention 
     The present disclosure relates to production logging. More specifically, the present disclosure relates to a system and method of deploying sensors in a hydrocarbon producing wellbore, sensing wellbore conditions with the sensors, and retrieving the sensors. 
     2. Description of Prior Art 
     Various types of devices are disposed downhole for monitoring parameters of fluid flowing within a wellbore, and evaluating subterranean formation adjacent the wellbore. Typically fluid parameters monitored downhole include a flowrate of fluid flowing downhole, fluid properties, and fluid conditions. Fluid properties monitored generally include fluid density, composition, and viscosity, and fluid conditions monitored usually include fluid pressure and fluid temperature. The formation properties typically estimated are resistivity, rugosity, and porosity. Flowmeters are typically used for measuring fluid flow, and sensors are typically used for measuring fluid properties and/or conditions. The flowmeters and sensors are deployed downhole within a producing wellbore, a jumper/caisson used in conjunction with a subsea wellbore, or a production transmission line used in distributing the produced fluids. Formation properties are typically measured with nuclear or electromagnetic tools. Monitoring fluid produced from a wellbore, and the formation properties, is useful in wellbore evaluation and to project production life of a well. Fluid density and viscosity are usually measured to estimate the type of fluid flowing in the monitored portion of the wellbore, i.e. oil, water, gas. A further determination of the fluid downhole can be verified by readings of temperature and/or pressure. 
     As is known, the downhole in-situ conditions of temperature and pressure can change significantly depending on the location in the borehole. Fluid properties, such as viscosity and density are dependent on fluid temperature and pressure, thus these properties for the same fluid can change depending on where the fluid is in the wellbore. Additionally, dissimilar types of fluids that are connate in the formation can migrate into the wellbore, thereby further altering the properties of the fluid flowing in the wellbore. Currently, downhole sensors for measuring fluid properties and sensors for measuring flow are disposed at different places in the wellbore or are spaced sufficiently far apart from one another that the fluid being monitored has different fluid properties when evaluated by these spaced apart sensors. Accordingly, these readings are susceptible to error if a flow rate calculation is based on an inaccurate value of fluid property. Permanently disposed sensors partially obstruct fluid flow in the wellbore, which can increase pressure drop of fluid being produced. Further, temporary sensors are mounted onto downhole tools, where the presence of the downhole tool affects the measurements obtained by the sensors. 
     SUMMARY OF THE INVENTION 
     Disclosed herein is an example of a logging tool for use in a wellbore and which includes a mother tool, a stinger depending from an end of the mother tool, and a sensor assembly selectively coupled to and decoupled from the stinger with a latch, and that is selectively landed in a designated location in the wellbore when decoupled from the stinger. The sensor assembly can be a sensor element for sensing a fluid; or can be one or more of a flow meter, a temperature sensor, a pressure sensor, or a density sensor. Optionally, the sensor assembly is a sensor for sensing a formation; which can be one or more of a resistivity sensor, a porosity sensor, and a rugosity sensor. The logging tool can further include proximity sensors on the sensor assembly and the stinger, so that when the mother tool is separated from the landed sensor assembly and being moved towards the sensor assembly in the wellbore, signals from the proximity sensors indicate relative locations of the sensor assembly and the stinger. In one alternative, the sensor assembly is in a retracted configuration and set radially inward from walls of the wellbore when the logging tool is being lowered in the wellbore, and wherein the sensor assembly is in a deployed configuration and in engaging contact with the walls of the wellbore when landed in the wellbore. The logging tool can further optionally include a plurality of additional sensor assemblies, so that the sensor assembly and the plurality of additional sensor assemblies make up a sensor set. In one specific example, the sensor assembly is formed from a hub that circumscribes the stinger when the sensor assembly is coupled with the stinger, arms that have an end connected to the hub and that project axially away from the hub when the sensor assembly is in a retracted configuration, the arms projecting radially away from the hub when the sensor assembly is in a deployed configuration, and sensor elements on the arms. A tool controller can be included and that is for controlling the latch, so that when the tool controller transmits a signal to the latch, the sensor assembly is decoupled from the stinger, and when the tool controller transmits another signal to the latch, the sensor assembly is coupled to the stinger. 
     Another example of a logging tool for use in a wellbore is described herein and that includes a mother tool having an upper end connected to a conveyance element, a sensor assembly selectively coupled to and decoupled from the mother tool, and a communication system in communication between the sensor assembly and mother tool. This example of the logging tool can further include an elongated stinger extending from an end of the mother tool distal from the upper end. The communication system can include a transceiver that is coupled with the mother tool and a transceiver that is coupled with the sensor assembly. In this example, the sensor assembly is made up of sensor elements that are in communication with the transceiver that is coupled with the sensor assembly. 
     Also described herein is a method of logging in a wellbore and which involves deploying a mother tool with a sensor in the wellbore, decoupling the sensor from the mother tool and anchoring the sensor at a designated depth in the wellbore, moving the mother tool uphole from where the sensor is anchored in the wellbore, and communicating between the mother tool and sensor. The method can further include moving the mother tool downhole and recoupling the sensor to the mother tool. Optionally included with the method is a step of sensing a proximity between the mother tool and the sensor when the sensor decoupled from the mother tool. The sensor can be a plurality of sensors that are spaced apart from one another on the mother tool when the mother tool is deployed in the wellbore, and that are decoupled from the mother tool and anchored in the wellbore at different depths of the wellbore. Optionally, the sensor senses data in the wellbore and communicates the data to the mother tool; where the data in the wellbore can be fluid pressure, fluid temperature, fluid flow, formation porosity, and formation resistivity. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
       Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which: 
         FIG. 1  is a side partial sectional view of an example of a logging tool having a sensor set of sensor assemblies, and disposed in a wellbore. 
         FIG. 2A , which is taken along lines  2 A- 2 A of  FIG. 1 , is an axial view of an example of a sensor assembly of  FIG. 1  in a retracted configuration. 
         FIG. 2B , which is taken along lines  2 B- 2 B of  FIG. 4 , is an axial view of an example of a sensor assembly in a deployed configuration. 
         FIGS. 3-8  are side sectional views of an example of the logging tool deploying and landing the sensor assemblies of  FIG. 1  in a deviated portion of the wellbore. 
         FIG. 9  is a side sectional view of an example of the sensor assemblies being landed and sensing conditions in the wellbore. 
         FIGS. 10-15  are side sectional views of the logging tool of  FIG. 1  retrieving the sensor set of sensor assemblies. 
     
    
    
     While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF INVENTION 
     The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of the cited magnitude. In an embodiment, usage of the term “substantially” includes +/−5% of the cited magnitude. 
     It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. 
     Depicted in side sectional view in  FIG. 1  is an example of a downhole tool  10  within a wellbore  12 , wherein the wellbore  12  intersects a formation  14 . The downhole tool  10  is shown suspended from a wireline  16 , which is used to deploy the downhole tool  10 , and through which communication to and from the downhole tool  10  is transmitted. Alternate conveyance means may be used for inserting and retrieving the downhole tool  10  from wellbore  12 , such as coiled tubing, slick line, cable and the like. An end of wireline  16  opposite from its connection to downhole tool  10  is shown within a service truck  18  provided on the surface  20  and adjacent an opening of wellbore  12 . Wireline  16  is threaded through a wellhead assembly  22  which is mounted on surface  20  and over the wellbore  12 . In the example of  FIG. 1 , the downhole tool  10  includes a mother tool  24  which has a generally cylindrical outer profile, and an elongated stinger  26  shown depending from an end of the mother tool  24  opposite to where it connects to wireline  16 . Sensor assemblies  28   1-3  are shown mounted on and coupled to stinger  26  and which define a sensor set  30 . As will be described in more detail below, coupling and decoupling of sensor assemblies  28   1-3  from stinger  26  can be controlled by a tool controller  31  which is depicted in dashed outline and disposed within mother tool  24 . Tool controller  31  is in selective communication with a surface controller  32  shown disposed within service truck  18 . Communication between the controllers  31 ,  32  can be along communication means (i.e. conductive media or fiber optics) in wireline  16 , or wireless along the wellbore  12 . 
       FIG. 2A , which is taken along lines  2 A- 2 A on  FIG. 1 , shows in an axial sectional view an upward looking example of the lower end of downhole tool  10  disposed within wellbore  12 . In the illustrated example, casing  33  is shown lining the walls of wellbore  12 . Here, the sensor assembly  28   1  is in a retracted configuration, so that its outer periphery is spaced radially inward from an inner surface of the casing  33 . In one example, while in the retracted configuration, the sensor assembly  28   1  is coupled to the stinger  26 . 
       FIG. 3  shows in a side sectional view the downhole tool  10  with sensor assemblies  28   1-3  in a deviated section of wellbore  12  and being guided past a series of perforation arrays  34   1-3 . The perforation arrays  34   1-3  are made up of a number of perforations P, which are openings in the formation  14  that extend radially outward from the wellbore  12 . Connate fluid F in the formation  14  flows into the wellbore  12  through the perforations P. 
       FIG. 4  illustrates in side sectional view, an example of sensor assembly  28   1  having been radially expanded into a deployed configuration and anchored within wellbore  12  between perforation arrays  34   1  and perforation array  34   2 . In an alternative, the sensor assembly  28   1  is deployed when the downhole tool  10  is at a designated depth in the wellbore  12 .  FIG. 2B , which is taken along lines  2 B- 2 B of  FIG. 4 , shows an axial sectional view of an example of sensor assembly  28   1  in the deployed configuration. In the deployed configuration, the outer periphery of sensor assembly  28   1  is in contact with and anchored to the walls of wellbore  12 , and as shown are in close contact with the inner surface of casing  33 . Further, when in the deployed configuration, sensor assembly  28   1  is decoupled from stinger  26  so that downhole tool  10  can be moved within wellbore  12  while sensor assembly  28   1  remains anchored in a designated depth of wellbore  12 . Optionally, production tubing (not shown) is inserted within the casing  33  and provides a flow conduit for conveying the connate fluid F to surface. In this example, the downhole tool  10  is inserted into the production tubing. 
     Shown in  FIG. 5  is an example of operation where the downhole tool  10  is drawn up hole within wellbore  12  after the sensor assembly  28   1  is put into the deployed configuration and anchored in the wellbore  12 . Referring to  FIG. 6 , sensor assembly  28   2  is shown converted into the deployed configuration and anchored within wellbore  12 . In the example of  FIG. 6 , sensor assembly  28   2  is anchored in a portion of the wellbore  12  that is between perforation arrays  34   2 ,  34   3 . In the example of  FIG. 7  downhole tool  10  is drawn further up hole within wellbore  12  after sensor assembly  28   2  is deployed and anchored in wellbore  12 , and decoupled from stinger  26 .  FIG. 8  illustrates an embodiment where sensor assembly  28   3  is set in the deployed configuration and in anchoring contact with sidewalls of wellbore  12 . In the example of  FIG. 8 , sensor assembly  28   3  is disposed in wellbore  12  on a side of perforation array  34   3  opposite from perforation array  34   2 . 
       FIG. 9  depicts an alternative where sensor assembly  28   3  is decoupled from stinger  26 , and the downhole tool  10  drawn further up hole in wellbore  12  and away from sensor assembly  28   3 . In the illustrated embodiment, sensor assemblies  28   1-3  are spaced apart from one another at different depths within wellbore  12  and at designated locations. As shown, the sensor assemblies  28   1-3  are strategically disposed between the perforation arrays  34   1-3  and can selectively monitor wellbore conditions, formation properties, fluid properties, and fluid flow in sections of the wellbore  12  that are between the perforation arrays  34   1-3 . In an alternative, the selective monitoring in these discrete locations provides estimated flow measurement and fluid properties from each of these perforation arrays  34   1-3  individually. Moreover, the anchoring of the sensor arrays  28   1-3  without the presence of the downhole tool  10 , results in more accurate measurements of flow of fluid F through wellbore  12  without interference from the downhole tool  10 . 
     Referring back to  FIG. 2B , each of the sensor assemblies, as illustrated by sensor assembly  28   1  in the deployed configuration, are shown to have a hub  36  which is selectively coupled to the stinger  26  by a latch mechanism  37   1 . Multiple examples of a latch  37   1  can be understood by those skilled in the art, such as dogs, tabs, collets, and the like. Thus when activated, latch  37   1  engages hub  36 , which couples sensor assembly  28   1  to stinger  26 . Control commands can cause latch  37   1  to retract thereby allowing stinger  26  to move axially with respect to hub  36  and sensor assembly  28   1  thereby allowing downhole tool  10  to move within the wellbore  12  with respect to the sensor assembly  28   1 . Further included with the sensor assemblies  28   1-3  are arms  38   1-6  which are elongate members whose elongate lengths project radially outward from hub  36  and into contact with the inner walls of wellbore  12  when sensor assembly  28   1  is in the deployed configuration. Referring back to  FIG. 2A , arms  38   1-6  project generally oblique to an axis A X  of downhole tool  10  when in the retracted configuration, thereby allowing deployment of downhole tool  10  within wellbore  12 . Referring back to  FIG. 2B , sensor elements  40  are shown coupled on the arms  38   1-6  at various radial locations on the arms  38   1-6 . The sensor elements  40  can be one or more of temperature sensors, pressure sensors, flow elements which can sense fluid flow temperature, fluid flow pressure, fluid flow rate, or any other measurable parameter of the fluid F in the wellbore  12 . Other examples of sensor elements  40  include sensors for sensing properties of the formation  14  adjacent wellbore  12 ; where examples of formation properties include porosity, density, resistivity, and rugosity. However, the sensor elements  40  can be used for sensing any downhole condition and whose use is not limited to that provided herein. Other examples of what can be measured by the sensor elements includes fluid type, fluid speed, fluid density, fluid viscosity, fluid acoustic properties, fluid electrical properties, fluid radioactive properties, fluid magnetic resonance properties, fluid optical properties, an amount of fluid flow, formation porosity, and formation resistivity 
     In a non-limiting example of operation as shown in  FIG. 9 , signals  44   1-3  are shown being transmitted within wellbore  12  between the sensor assemblies  28   1-3  and downhole tool  10 . Transmission and/or receipt of the signals  44   1-3  is selectively performed by transceivers  46   1-3  shown disposed respectively on the sensor assemblies  28   1-3 , and transceiver  48  that is provided within the mother tool  10 . Thus, data as described above can be sensed or collected by sensor assemblies  28   1-3  and transmitted to transceiver  48  from transceivers  46   1-3  and then communicated up hole via wireline  16  for storage and/or processing. Alternatively, less than all of the sensor assemblies  28   1-3  can be operating at one time and so that less than the number of signals illustrated in  FIG. 9  can be transmitted between sensor assemblies  28   1-3  and downhole tool  10 . Optionally, signals or data can be transmitted from transceiver  48  to sensor assemblies  28   1-3  for adjusting operation of the particular sensor assemblies  28   1-3 . In another example, data sensed by sensor assemblies  28   1-3  can be stored in data storage media (not shown) provided with the sensor assemblies  28   1-3 . Yet further optionally, the number of sensor assemblies  28   1-3  provided for use with the downhole tool  10  can be three as shown, greater than three, or less than three. In another alternate example, the signals  44   1-3  can be transmitted fully up hole and so that communication is directly between the sensor assemblies  28   1-3  and surface controller  32  of  FIG. 1 . Further, the positioning of the sensor assemblies  28   1-3  is not limited to the locations, spacing, or arrangements as shown. Instead, sensor assemblies  28   1-3  can be disposed adjacent one of the perforation arrays  34   1-3  rather than between, and more than one of the sensor assemblies  28   1-3  can be disposed proximate one another rather than spaced apart as shown. 
       FIG. 10  shows in a side sectional view an example of the downhole tool  10  being moved back downhole from its position of  FIG. 9 , and the stinger  26  being reinserted into sensor assembly  28   3 . Sensor assembly  28   3  recouples to downhole tool  10  after being engaged by stinger  26 , in an example latch  37   3  is selectively activated to affix sensor assembly  28   3  to stinger  26 . Further, sensors  28   k ,  28   2  can still be sending signals  44   k ,  44   2  during this process and continuing to sense data and conditions within borehole  12 .  FIG. 11  depicts an example where sensor assembly  28   3  is in the retracted configuration on stinger  26  so that as shown in  FIG. 12 , further downhole movement of downhole tool brings the stinger  26  into contact with sensor assembly  28   2 . Signal  44   1  is shown in wellbore illustrating that sensor assembly  28   1  and downhole tool  10  can be in communication with one another. In an example, signals  44   1-3  are wireless, which can be electromagnetic waves as well as mud pulses and the like. Optionally, hard wire examples exist wherein the sensor assemblies  28   1-3  maintain communication via conductive elements throughout the process of deployment and retrieval of the sensor assemblies  28   1-3 . In one example, one or more of the sensor assemblies  28   1-3  operates as a transponder that performs a wireless repeater function to allow communication between one or more of the other sensor assemblies  28   1-3  and the downhole tool  10  should the distance between the downhole tool  10  and the other sensors assemblies  28   1-3  exceeds its operating range.  FIG. 13  depicts an example where sensor assembly  28   2  is configured into its retracted configuration and so that downhole tool  10  can move deeper into the wellbore  12  and retrieve downhole assemblies  28   1-3  as illustrated in  FIGS. 14 and 15 . 
     Referring back to  FIG. 2B , optional proximity sensors  50   1  and  52  are illustrated, which can facilitate the coupling of stinger  26  to the sensor assemblies  28   1 . In an example of operation, proximity sensors  50   1 ,  52  sense their relative proximity to one another and generate signals reflective of the relative proximity of stinger  26  to sensor array  28   1 , which can be used by operations personnel to guide stinger  26  into hub  36  of sensor array  28   1 . Similarly, proximity sensors (not shown) can also be provided on other sensor arrays  28   2, 3  ( FIG. 3 ) so that downhole tool  10  can be guided to recouple the sensor arrays  28   2, 3  to the stinger  26  so they can be retrieved to surface  20 . Optionally, transceivers  46   1-3 ,  48  ( FIG. 9 ) can be in communication with one another in order to provide guiding signals for reattaching sensor arrays  28   1-3  to downhole tool  10 . 
     In an alternate embodiment, each of the sensor assemblies  28   1-3  of the sensor set  30  of  FIG. 1  are equipped with latching systems (not shown) for coupling to one another. Thus in this example, the stinger  26  can optionally be omitted from the tool  10  and one of the sensor assemblies  28   1-3  configured to be coupled directly to the mother tool  24 , and the remaining sensor assemblies  28   1-3  couple to one another, so that the sensor set  30  depends directly from the mother tool  24 . Moreover, the sensor assemblies  28   1-3  can also be electrical and signal communication with one another independently or through the latching system. In one embodiment, a downhole setting tool (not shown), such as those currently used for setting and retrieving an inflatable plug, is included with the tool  10 . In this example, a driving tool is set in each of the sensor assemblies  28   1-3 , such as within a receptacle, and that rotates to set and release the particular one of the sensor assemblies  28   1-3 . The setting tool can also be used to retrieve the sensor assemblies  28   1-3  where the driving tool inserts into the sensor assemblies  28   1-3  and rotated to retract the sensor assemblies  28   1-3  and then retrieve them from the wellbore  12 . In one example, each of the sensor assemblies  28   1-3  includes an electrical motor and gear box, that when selectively energized provides power to the sensor assemblies  28   1-3  for orienting them into the set and unset configurations. An inductively coupled electrical power receiver/repeater scheme can also be included in this configuration. 
     The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.