US20100132955A1 - Method and system for deploying sensors in a well bore using a latch and mating element - Google Patents

Method and system for deploying sensors in a well bore using a latch and mating element Download PDF

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Publication number
US20100132955A1
US20100132955A1 US12626213 US62621309A US2010132955A1 US 20100132955 A1 US20100132955 A1 US 20100132955A1 US 12626213 US12626213 US 12626213 US 62621309 A US62621309 A US 62621309A US 2010132955 A1 US2010132955 A1 US 2010132955A1
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Prior art keywords
wellbore
sensor array
tubular
body
mating element
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Abandoned
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US12626213
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Bruce H. Storm, Jr.
Eugene Murphy
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KENDA BV
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Misc BV
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/01Devices for supporting measuring instruments on a drill pipe, rod or wireline ; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/02Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for locking the tools or the like in landing nipples or in recesses between adjacent sections of tubing
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/14Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for displacing a cable or cable-operated tool, e.g. for logging or perforating operations in deviated wells

Abstract

A method for deploying a sensor array into a wellbore, including inserting the sensor array into a secondary tubular coupled to a body at a surface of the wellbore, coupling the sensory array to the body, running the secondary tubular into a primary tubular fixed to the wellbore, engaging a latch mechanism located on the body with a mating element fixed to the primary tubular of the wellbore, and decoupling the secondary tubular from the body and retrieving the secondary tubular from the wellbore while the sensor array is held fixed by the latch.

Description

    BACKGROUND
  • Typically, a wellbore is formed by advancing a down hole drilling tool having a drill bit at one end into the ground. As the drilling tool is advanced, drilling fluid (“mud”) is pumped from a surface mud pit through a passage or passages in the drilling tool and out the drill bit. The mud exiting the drill bit flows back to the surface to be returned to the mud pit and may be re-circulated through the drilling tool. In this manner, the drilling mud cools the drilling tool, carries cuttings and other debris away from the drilling tool, and deposits the cuttings and other debris in the mud pit. As is known, in addition to the cooling and cleaning operations performed by the mud pumped into the wellbore, the mud forms a mudcake that lines the wellbore which, among other functions, reduces friction between the drill string and subterranean formations.
  • During drilling operations (i.e., advancement of the down hole drilling tool), communications between the down hole drilling tool and a surface-based processing unit and/or other surface devices may be performed using a telemetry system. In general, such telemetry systems enable the conveyance of power, data, commands, and/or any other signals or information between the down hole drilling tools/bottom hole assemble (BHA) and the surface devices. Thus, the telemetry systems enable, for example, data related to the conditions of the wellbore and/or the down hole drilling tool to be conveyed to the surface devices for further processing, display, etc. and also enable the operations of the down hole drilling tool to be controlled via commands and/or other information sent from the surface device(s) to the down hole drilling tool.
  • Such telemetry systems typically include sensors that are used to monitor down hole formation properties during drilling and production, and to control the well bore conditions to maximize the production of the well bore over time. For example, sensors may be used to monitor temperature in oil wells, measure electric current to characterize the reservoir, etc. Sensors are also used for seismic applications. Typically, seismic measurements are normally undertaken with acoustic sensors which can be towed behind ships in large arrays, or positioned on land.
  • Sensors may be deployed into well bores in a variety of ways. In vertical wellbores and semi-vertical wellbores which are not highly deviated, objects such as wirelines, cables, sensors, coiled tubing, tubular strings, and tools introduced into the wellbore move down into the wellbore by the force of gravity. To facilitate the deployment of objects, such as sensors, in a horizontal well bore, various well bore tractor systems are used. An example of such a tractor system is an anchor-and-ram-unit assembly for propelling a drilling tool in a wellbore. The assembly has two anchor assemblies each with anchor feet that are hydraulically activated to move out and engage an interior wellbore wall. Alternatively, objects may be deployed in a horizontal well-bore by attaching them to the end of a tubular string and then moving the tubular string with a prime mover into a wellbore. The prime mover does not enter the wellbore. Sensor arrays may also be deployed into well bores by pumping them through hydraulic conduits or chemical injection lines. Typically, well bore tractor systems require down hole power, motors, and/or electronics while providing limited pulling capability. Accordingly, there exists a need for an efficient and inexpensive method for deploying sensors into a wellbore.
  • SUMMARY
  • In general, in one aspect, the invention relates to a method for deploying a sensor array into a wellbore, comprising inserting the sensor array into a secondary tubular coupled to a body at a surface of the wellbore, coupling the sensory array to the body, running the secondary tubular into a primary tubular fixed to the wellbore, engaging a latch mechanism located on the body with a mating element fixed to the primary tubular of the wellbore, and decoupling the secondary tubular from the body and retrieving the secondary tubular from the wellbore while the sensor array is held fixed by the latch.
  • In general, in one aspect, the invention relates to an apparatus for deploying a sensor array into a wellbore comprising a primary tubular, the apparatus comprising a body into which an end of a cable is fixed, wherein the body comprises a seating lip configured to engage a secondary tubular housing the cable and the sensor array, and a latch mechanism operatively connected to the body, wherein the latch mechanism is configured to engage with a mating element fixed to the primary tubular, wherein the engagement of the latch mechanism and the mating element secure the sensor array in a down hole position while the secondary tubular is withdrawn from the wellbore.
  • In general, in one aspect, the invention relates to a system for deploying a sensor array into a primary tubular of a wellbore, the system comprising a primary tubular comprising a latch mating element, and a sensor array deployment apparatus comprising a body, a secondary tubular configured to house the sensor array, a cable extending through the secondary tubular and coupled to the body, and a latch mechanism disposed on the body and configured to engage the latch mating element of the primary tubular.
  • Other aspects of the invention will be apparent from the following description and the appended claims.
  • BRIEF DESCRIPTION OF DRAWINGS
  • FIG. 1 shows a secondary tubular for deploying a sensor array in accordance with one or more embodiments of the disclosure.
  • FIG. 2 shows a secondary tubular for deploying a sensor array with coil springs in accordance with one or more embodiments of the disclosure.
  • FIG. 3 shows a secondary tubular for deploying a sensor array with shear pins in accordance with one or more embodiments of the disclosure.
  • FIG. 4 shows a retaining lip assembly in accordance with one or more embodiments of the disclosure.
  • FIG. 5 shows a flow chart for deploying a sensor array in accordance with one or more embodiments of the disclosure.
  • DETAILED DESCRIPTION
  • Specific embodiments will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.
  • In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
  • In general, one or more embodiments disclosed herein provide a method and apparatus to deploy a sensor array into a wellbore. Specifically, embodiments disclosed herein provide a method and apparatus for deploying a latched sensor array into a wellbore using a secondary tubular, where the latch mechanism associated with the sensor array assembly engages with a mating element fixed to the primary tubular of the wellbore to provide proper positioning of the sensor array within the wellbore.
  • FIG. 1 shows an apparatus for deploying a sensor array into a wellbore in accordance with one or more embodiments disclosed herein. Specifically, FIG. 1 shows a lead-in body (102), a primary tubular (103), a sensor array cable (104), a secondary tubular (105), a retaining lip (106), a seating lip (108), a latch mechanism (110) (e.g., a spring mechanism), a cable keeper (112), and a bulkhead (114). Each of the aforementioned components of the apparatus of FIG. 1 are described below.
  • In one or more embodiments disclosed herein, a sensor array may be deployed into a horizontal or steeply deviated wellbore. Specifically, embodiments disclosed herein provide a method and apparatus that allows the running of a sensor array cable into a horizontal or steeply deviated wellbore (i.e., in which gravity does not sufficiently aid the running of a cable into a wellbore) that does not require use of a well tractor or other heavy and/or costly equipment. Those skilled in the art will appreciate that while a common application of embodiments disclosed herein pertains to deployment of sensors in a horizontal or steeply deviated wellbore, embodiments of the disclosure may also be implemented in vertical wellbores. In one or more embodiments, the sensor array may include temperature, pressure, position or seismic sensors for sensing seismic energy transmitted through the earth formation. Such seismic sensors include, but are not limited to, geophones, hydrophones, and accelerometers.
  • A primary tubular (103) is disposed in the wellbore (not shown). The primary tubular (103) may be a casing that is cemented (or otherwise permanently fixed) into the wellbore. For example, the primary tubular (103) may be a string of steel pipe that provides support to the wellbore and facilitates the isolation of certain areas of the wellbore. In one or more embodiments disclosed herein, the primary tubular (103) includes a mating element (106), e.g., a retaining lip, that is fixed to the primary tubular (103) (discussed below). In one or more embodiments disclosed herein, the sensor array is inserted into a secondary tubular (105) coupled to the lead-in body (102). The secondary tubular (105) is then inserted into the primary tubular (103) of the wellbore.
  • In one or more embodiments disclosed herein, the lead-in body (102) is in the shape of a pointed head, which facilitates the conveyance of the secondary tubular into the primary tubular (103) of the wellbore. One of ordinary skill in the art will appreciate that other geometrical configurations of the lead-in body may be used. The lead-in body (102) includes a bulkhead (114) and a seating lip (108) for engaging the secondary tubular. The seating lip (108) allows the secondary tubular (105) to be operatively connected to the lead-in body (102). In one embodiment of the disclosure, the secondary tubular is seated within the seating lip (108). In alternate embodiments, the secondary tubular may be threaded with the seating lip (108). The end of the sensor array cable (104) is fixed to the lead-in body (102) by a cable keeper (112). Those skilled in the art will appreciate that the arrangement of a cable that is held in position by a cable keeper (112) is well known in the art, and thus, is not described in detail in the present disclosure. Further, the lead-in body (102) includes an extension portion on either side. The extension portion is configured to house a latch mechanism (110), such as a spring mechanism. The extension portion may be an arm, a blade, or any other suitable extended structure on an outer surface of the lead-in body (102). The lead-in body (102) may include one, two, or more latch mechanism, and therefore, may include a corresponding one or more extension portions.
  • The secondary tubular (105) provides a setting force to facilitate the setting of the lead-in body (102) into the primary tubular (103) of the wellbore. Thus, in one or more embodiments of the disclosure, the secondary tubular (105) is used to convey the sensor array into the primary tubular (103). Further, the secondary tubular (105) is a conveyance tubing that protects the sensor array during deployment into the primary tubular (103) of the wellbore. In one or more embodiments disclosed herein, the secondary tubular (105) is a continuous or jointed tubing string. For example, in one embodiment of the disclosure, the secondary tubular (105) may be a coiled tubing string. Alternatively, the secondary tubular (105) may be a polymer of vinyl chloride (PVC) tubular, or any other suitable tubular that is configured to provide force to set the lead-in body (102) into the primary tubular (103).
  • Continuing with FIG. 1, a sensor array cable (104) includes a load-bearing cable that is attached to the lead-in body (102) by the cable keeper (112). The sensor array cable (104) may be a wire line cable, a fiber optic cable, or any other suitable cable. Further, the load-bearing cable may be braided, helically wound, or a straight line cable. The sensor array cable (104) is operatively connected to a conductor cable (not shown) on which the sensor array is located. More specifically, the conductor cable is an electrical cable on which the sensor array is located. The sensor array may be embedded into or located on the surface of the conductor cable. The conductor cable may be disposed inside, or alternatively, outside of the sensor array cable (104).
  • The mating element (106) is configured to engage the latch mechanism (110) associated with the sensor array. In one or more embodiments of the disclosure, the mating element (106) is a protrusion that is fixed into the primary tubular (103) of the wellbore. Alternatively, the mating element (106) may include more than one protrusion or a circumferential protrusion around the inner circumference of the primary tubular (103). In an alternate embodiment, the mating element may be a recess in the primary tubular (103) rather than a protrusion configured to receive the latch mechanism associated with the sensory array. More specifically, in one or more embodiments disclosed herein, the mating element (106) is a retaining lip. The mating element (106) may be welded, machined, or driven into the primary tubular (103). In addition, the mating element (106) may be symmetric (e.g., hemispherical) with a radius that is tapered from up-hole and down hole. Alternatively, the mating element (106) may be asymmetric (e.g., a quarter radius) with a substantially flat down-stream surface to prevent the lead-in body from moving upward without the application of appreciable force after engagement with the mating element. Those skilled in the art will appreciate that the mating element may be any desired shape, and is not limited to a semi-circle or quarter radius configuration. For example, the mating element may be a rectangle, a cone, a tapered or contoured surface or any other suitable shape. In addition, the mating element (106) may be spring-loaded, such that the mating element (106) is compressed when the lead-in body (102) passes over the mating element (106). In one or more embodiments disclosed herein, the mating element (106) of the primary tubular (103) may be provided by a close tolerance friction fit with the lead-in body (102).
  • The latch mechanism (110) is configured to engage with the mating element (106). In one or more embodiments of the disclosure, the latch mechanism (110) is located on the lead-in body (102) at a lower end or below the sensor array. More specifically, the latch mechanism (110) includes an extension portion of the lead-in body (102). In one or more embodiments disclosed herein, the latch mechanism (110) may further include a spring mechanism. In this embodiment, the latch mechanism (110) may include bow springs, coiled springs, leaf springs, and/or any combination thereof. Alternatively, other suitable configurations for a spring mechanism, such as spring deployed collets, pins or balls, may also be employed as a latch mechanism that is associated with the sensor array. In one or more embodiments disclosed herein, the latch mechanism (110) is attached to the lead-in body (102) which secures the end of the sensor array cable (104). In one or more embodiments, the latch mechanism (110) is used to anchor against the primary tubular (103). Those skilled in the art will appreciate that if the mating element (106) is spring loaded, for example, then the latch mechanism (110) may be fixed to the lead-in body, and the spring constant of the mating element (106) is selected on the desired latch/release load for setting and/or removing the lead-in body (102) from the primary tubular (103).
  • The latch mechanism (110) and mating element (106) (e.g., the spring mechanism and the retaining lip) provide a mechanism for retaining the body in position down hole. The secondary tubing containing the sensor array is run into the borehole until the lead-in body is adjacent to the mating element. At this point, the resistance to further downward motion increases This increase in resistance may be used to provided an indication that the lead-in body has landed at the mating element. Once a sufficient compression force or load is applied to the secondary tubular (105), the latch mechanism (110) collapses radially inward as it moves over the mating element (106) and the lead-in body (102) is forced to pass the mating element (106). As it passes the mating element, the spring element is allowed to expand outwardly, thus providing a latch which resists the lead-in body and sensor array being withdrawn when the secondary tubing is extracted from the well bore.
  • FIG. 2 shows the apparatus of FIG. 1, in which the latch mechanism is a spring-loaded mechanism (202), and in which the mating element is shown as a retaining lip (200). Specifically, the spring mechanism (202) includes one or more coil springs. As described above, the spring mechanism (202) may include leaf springs, bow springs, or any other suitable spring mechanism and is not limited to coil springs as shown in FIG. 2. In one or more embodiments disclosed herein, the coiled springs are seated up against the lead-in body (102) of the conveyance tubing. However, those skilled in the art will appreciate that the spring mechanism may be positioned such that each spring passes through the body (102) or in any other suitable position that provides increased normal force thereby increasing the friction between the body (102) and the retaining lip (200) as the spring mechanism passes the retaining lip (200) so that the lead-in body (102) (and thereby the sensor array) may be positioned within the primary tubular (103) where desired.
  • FIG. 3 shows another embodiment of a latch mechanism associated with a sensor array. Specifically, in one or more embodiments of the disclosure, the latch mechanism and mating element (106) that engage together to fix the sensor array into the primary tubular (103) of the wellbore may be a shear pin (302) and a retaining lip, respectively. In this embodiment, a shear pin (302) attached to the lead-in body (102) and is configured to secure the sensor array into a desired location within the primary tubular (103) of the wellbore, in accordance with one or more embodiments disclosed herein. As shown in FIG. 3, as the lead-in body is moved into the wellbore, the shear pin (302) is pushed against the arc portion of the retaining lip, and the spring of the shear pin (302) is pushed inward, as the spring is compressed. More specifically, for example, as the shear pin (302) moves against the quarter radius shape of the retaining lip, the shear pin (302) is pressed inward against the spring mechanism until the shear pin latch (302) passes the retaining lip. When the retaining lip is passed, the shear pin (302) may move radially outward. The shear pin (302) has a predetermined shear force, such that the shear pin remains intact, holding the lead-in body and sensor array in the well bore while the secondary tubular is removed. The shear pin may shear (i.e., break off) when the applied upward tension on the cable exceeds the predetermined shear force. Thus, to remove the sensor array from the primary tubular (e.g., after seismic and/or survey data has been obtained), tension is applied by pulling the sensor array cable out of the primary tubular such that the shear pin shears (302), thereby disengaging the latch mechanism and mating element.
  • As described above, although FIG. 3 shows the spring portion of the shear pin (302) as seated up against the lead-in body, embodiments of the disclosure may be implemented with a latch mechanism that is positioned through the lead-in body. For example, the coil springs shown in FIG. 2 may be positioned through the lead-in body rather than within the extension portion of the lead-in body.
  • FIG. 4 shows a retaining lip assembly in accordance with one or more embodiments disclosed herein. Specifically, FIG. 4 shows a retaining lip assembly (401) that can be used to insert a mating element, e.g., retaining lip (400) into a primary tubular (103) of a wellbore that does not already include a retaining lip or other mating element. The retaining lip assembly includes a sleeve (401), which includes a flange (402) on the end of the sleeve (401) that is configured to engage an end of the primary tubular (103) of the wellbore. At least one retaining lip (400) is fixed to the assembly. The end flange (402) engages onto the end of the primary tubular (103) in the wellbore. The retaining lip (400) assembly may be run into the primary tubular using methods well known in the art. In one or more embodiments disclosed herein, the retaining lip assembly is friction fitted to the primary tubular (103). The retaining lip protrusion may be positioned anywhere along the sleeve (401) of the retaining lip assembly. Further, the flange (402) may be positioned anywhere along the primary tubular (103), and not necessary located on the end of the primary tubular (103) in the wellbore. For example, in one or more embodiments disclosed herein, the end flange (402) that is located on the end of the primary tubular (103) may be omitted, allowing the retaining lip assembly to be positioned several joints from the end of the primary tubular (103). In this case, the retaining lip assembly may be fixed in position in the primary tubular by a close tolerance friction fit between the retaining lip assembly and the primary tubular, by welding the retaining lip assembly to the ID of the primary tubular, or by other suitable attachment known in the art (e.g., threaded coupling, bolt, or through pin).
  • Those skilled in the art will appreciate that in the embodiment in which the retaining lip assembly is friction fitted with the primary tubular (103), the frictional force between the sleeve (401) and the primary tubular (103) is greater than the force applied when inserting or removing the lead-in body. Those skilled in the art will appreciate that the clearance between the parts shown in FIG. 4 is exaggerated for purposes of clarity and illustration.
  • FIG. 5 shows a flow chart for deploying a sensor array into a wellbore in accordance with one or more embodiments disclosed herein. While the various steps in the flowchart of FIG. 5 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Accordingly, the specific arrangement of steps shown in FIG. 5 is not meant to limit the scope of the invention.
  • Initially, the sensor array cable that includes the sensor array on a conductor cable is inserted into a secondary tubular at the surface above the wellbore (ST 500). In one or more embodiments disclosed herein, the sensor array is coupled to a latch mechanism. Subsequently, the secondary tubular is run into a primary tubular of the wellbore (ST 502). The secondary tubular includes a lead-in body that facilitates movement of the secondary tubular into the horizontal or steeply deviated wellbore. Further, the secondary tubular provides the setting force that allows the lead-in body of the secondary tubular, e.g., conveyance tubing, to engage a retaining lip on the inner surface of the primary tubular.
  • At this stage, the secondary tubular continues to move down hole until the latch mechanism of the sensor array is engaged with a mating element fixed onto the primary tubular of the wellbore (ST 504). The latch mechanism may be a spring mechanism that includes one or more springs. The mating element may be any protrusion or recess in the primary tubular that is configured to engage the latch mechanism. For example, the mating element may be a retaining lip. In one or more embodiments disclosed herein, the secondary tubular is used to apply axial force to the lead-in body, which is required to collapse the spring mechanism when the springs engage the retaining lip (e.g., from the up-hole side). When the springs of the spring mechanism reach the retaining lip that is fixed to the primary tubular, the force required to translate (i.e., continue movement of) the secondary tubular increases, because the spring(s) of the secondary tubular must collapse to pass the retaining lip, thereby securing the lead-in body to the primary tubular. In one or more embodiments disclosed herein, this increase in force may be measured at the surface. Alternatively, the deployment condition of the latch mechanism may be sensed down hole (e.g., by proximity sensor, stress sensor, load cell, a combination thereof, or any other suitable sensing element) and communicated to the surface. When the spring(s) pass the retaining lip, the force required to translate the secondary tubular drops.
  • Once the latch mechanism and mating element engage, the sensor array is fixed into position in the wellbore. The secondary tubular is then disengaged from the lead-in body and withdrawn from the primary tubular while the sensor array is held fixed by the mated latch (ST 506). Specifically, the secondary tubular may be unthreaded or pulled up. Thus, the lead-in body and the seating lip of the lead-in body remain in the primary tubular, while the secondary tubular is removed after the latch mechanism and mating element are engaged and the sensor array is positionally fixed into the primary tubular. The cable may be tensioned from the surface to assure no slack in the cable along the array which would introduce uncertainty in spacing between sensors. Applying tension to the cable results in the sensor spacing being fixed by the length of cable between adjacent sensors. Those skilled in the art will appreciate that while the discussion above focuses on the sensor array being inserted all the way down hole (e.g., to the end of the primary tubular of the wellbore), embodiments disclosed herein may also apply to a sensor array that is inserted into the middle of a wellbore or any desired axial location within the wellbore, and not necessarily at the end of the wellbore. In the same manner discussed above, the increase in force to pass the retaining lip located at the desired position of the wellbore indicates when the sensor array has reached the appropriate location in the wellbore.
  • In one or more embodiments disclosed herein, the sensor array is deployed for seismic monitoring within the wellbore. The sensor array may also be used in hydrophone and/or geophone applications. In addition, the sensor array may be used to collect data for purposes of surveying, production monitoring, for advanced stages of drilling, or any other oilfield application for which sensors may be used to collect data.
  • Continuing with FIG. 5, tension is applied to the sensor array cable to disengage the mated latch mechanism (ST 508). In one or more embodiments disclosed herein, the tension applied to the sensor array cable is sufficient to overcome the engaging mechanism of the latch, so that the sensor array cable may be retrieved after measurements have been taken. That is, the sensor array cable is withdrawn by pulling on the sensor array cable so that the latch mechanism of the lead-in body moves past the retaining lip toward the surface (i.e., up hole). In one embodiment, the force of the springs in the latch mechanism of the sensor array is less than the tensile strength of the sensor array cable, such that the sensor array cable may be retrieved and returned to the surface by pulling the sensor array cable without running the coiled tubing into the wellbore to retrieve the sensor array cable. In another embodiment, the shear strength of shear pins in the latch mechanism of the sensor array is less than the tensile strength of the sensor array cable, such that the sensor array cable may be retrieved and returned to the surface by pulling the sensor array cable without running the coiled tubing into the wellbore to retrieve the sensor array cable. Those skilled in the art will appreciate that the sensor array cable may be removed at any point in time after the sensor array is latched, and seismic measurements (or any other type of data) have been obtained. Once the latch mechanism is disengaged, the sensor array may be withdrawn from the wellbore primary tubular (ST 510).
  • In one or more embodiments disclosed herein, although not shown in FIG. 5, the sensor array may be redeployed into the wellbore after the sensor array is extracted from the wellbore. Thus, the sensor array provides value both for initial deployment and re-deployment. Specifically, the sensor array may be placed in essentially the same position when the sensor array is redeployed. In one or more embodiments of the disclosure, calibration involving position encoding on the sensor array and use of triangulation may be used to determine the position of the sensor array relative to the location where the sensor array was previously deployed.
  • Advantageously, embodiments disclosed herein provide a method for running a sensor array into a horizontal or steeply deviated wellbore and removal of the sensor array from the wellbore without use of a well tractor or other heavy machinery. The apparatus and method disclosed herein are inexpensive and reliable for deploying sensors in horizontal wells, where gravity does not sufficiently aid the running of the sensor array into the wellbore. The apparatus and method provides an accurate way to deploy and position the sensor array and allows a user to know when sensors are in a proper desired location within the wellbore.
  • While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims (20)

1. A method for deploying a sensor array into a wellbore, comprising:
inserting the sensor array into a secondary tubular coupled to a body at a surface of the wellbore;
coupling the sensory array to the body;
running the secondary tubular into a primary tubular fixed to the wellbore;
engaging a latch mechanism located on the body with a mating element fixed to the primary tubular of the wellbore; and
decoupling the secondary tubular from the body and retrieving the secondary tubular from the wellbore while the sensor array is held fixed by the latch.
2. The method of claim 1, further comprising:
retrieving the sensor array from the primary tubular by applying tension to a sensor array cable, wherein the tension applied is sufficient to overcome an engaging mechanism of the latch; and
releasing the latch and withdrawing the sensor array from the primary tubular of the wellbore.
3. The method of claim 1, wherein the secondary tubular is a coiled tubing string.
4. The method of claim 1, wherein the latch mechanism comprises an extension portion extending radially outward from the body.
5. The method of claim 1, wherein engaging the latch mechanism comprises friction fitting the latch mechanism to the mating element.
6. The method of claim 1, wherein the latch mechanism is spring-loaded and wherein the mating element is a retaining lip.
7. The method of claim 6, wherein engaging the latch mechanism comprises compressing at least one spring in the spring-loaded latch mechanism.
8. The method of claim 6, wherein the spring-loaded latch mechanism comprises one selected from a group consisting of coil springs, a spring loaded shear pin, bow springs, and leaf springs.
9. The method of claim 1, wherein the mating element is welded to the primary tubular of the wellbore.
10. The method of claim 1, wherein the mating element is affixed to a sleeve coupled to the primary tubular in the wellbore.
11. The method of claim 1, further comprising:
performing seismic monitoring in the wellbore using the deployed sensory array.
12. The method of claim 1, wherein the wellbore is one of a group consisting of a horizontal wellbore and a steeply deviated wellbore.
13. An apparatus for deploying a sensor array into a wellbore comprising a primary tubular, the apparatus comprising:
a body into which an end of a cable is fixed, wherein the body comprises a seating lip configured to engage a secondary tubular housing the cable and the sensor array; and
a latch mechanism operatively connected to the body, wherein the latch mechanism is configured to engage with a mating element fixed to the primary tubular;
wherein the engagement of the latch mechanism and the mating element secure the sensor array in a down hole position while the secondary tubular is withdrawn from the wellbore.
14. The apparatus of claim 13, wherein the latch mechanism is spring loaded, and wherein the spring-loaded latch mechanism comprises at least one of a group consisting of coil springs, a spring-loaded shear pin, bow springs, and leaf springs.
15. The apparatus of claim 13, wherein the mating element is welded to the primary tubular of the wellbore.
16. The apparatus of claim 13, wherein the secondary tubular is a coiled tubing string.
17. The apparatus of claim 13, wherein the mating element is affixed to at least one sleeve coupled to the primary tubular in the wellbore.
18. The apparatus of claim 17, wherein the mating element is friction fitted into the primary tubular.
19. The apparatus of claim 13, wherein the wellbore is one of a horizontal wellbore and a steeply deviated wellbore.
20. A system for deploying a sensor array into a primary tubular of a wellbore, the system comprising:
a primary tubular comprising a latch mating element; and
a sensor array deployment apparatus comprising:
a body;
a secondary tubular configured to house the sensor array;
a cable extending through the secondary tubular and coupled to the body; and
a latch mechanism disposed on the body and configured to engage the latch mating element of the primary tubular.
US12626213 2008-12-02 2009-11-25 Method and system for deploying sensors in a well bore using a latch and mating element Abandoned US20100132955A1 (en)

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