Patent Publication Number: US-8973679-B2

Title: Integrated reaming and measurement system and related methods of use

Description:
BACKGROUND 
     1. Field of the Disclosure 
     Embodiments disclosed herein relate generally to downhole tools. In particular, embodiments disclosed herein relate to expandable underreamers and related methods of use. 
     2. Background Art 
     In the drilling of oil and gas wells, typically concentric casing strings are installed and cemented in the wellbore as drilling progresses to increasing depths. Each new casing string is supported within the previously installed casing string, thereby limiting the annular area available for the cementing operation. Further, as successively smaller diameter casing strings are suspended, the flow area for the production of oil and gas is reduced. Therefore, to increase the annular space for the cementing operation, and to increase the production flow area, it is often desirable to enlarge the wellbore below the terminal end of the previously cased wellbore. By enlarging the wellbore, a larger annular area is provided for subsequently installing and cementing a larger casing string than would have been possible otherwise. Accordingly, by enlarging the wellbore below the previously cased wellbore, the bottom of the formation can be reached with comparatively larger diameter casing, thereby providing more flow area for the production of oil and gas. 
     Various methods have been devised for passing a drilling assembly through a cased wellbore, or in conjunction with expandable casing to enlarge the wellbore. One such method involves the use of an underreamer, which has basically two operative states—a closed or collapsed state, where the diameter of the tool is sufficiently small to allow the tool to pass through the existing cased wellbore, and an open or partly expanded state, where one or more arms with cutters on the ends thereof extend from the body of the tool. In this latter position, the underreamer enlarges the wellbore diameter as the tool is rotated and lowered in the wellbore. 
     Because the underreamer may be positioned a distance uphole from a drill bit on a distal end of the drillstring, an un-reamed portion of the wellbore, often referred to in the industry as the rat hole, may exist between the underreamer and the drill bit after the borehole is enlarged. In certain instances, the distance may be up to 125 feet or more. To underream the rat hole, the first underreamer is often removed from the wellbore and replaced with a second underreamer, requiring multiple trips into the wellbore. 
     Accordingly, there exists a need for an integrated reamer system capable of fully underreaming a wellbore and providing measurement data of the enlarged wellbore. 
     SUMMARY OF THE DISCLOSURE 
     In one aspect, embodiments disclosed herein relate to a downhole reaming system including a tubular body having a drill bit disposed on a distal end thereof, and a central bore therethrough, wherein the tubular body is attached to a drillstring, an expandable reamer having cutter blocks coupled thereto and configured to selectively expand radially therefrom, a near-bit reamer disposed proximate the drill bit, the near-bit reamer having cutter blocks coupled thereto and configured to expand therefrom, and a measurement sub configured to measure at least one characteristic of an interior wall of an enlarged wellbore. 
     In other aspects, embodiments disclosed herein relate to a method of enlarging a wellbore including running a drillstring having a tubular body attached thereto into a wellbore the tubular body comprising an expandable reamer, a drill bit disposed on a distal end of the tubular body, and a near-bit reamer located proximate the drill bit, expanding cutter blocks of the expandable reamer and enlarging a portion of the wellbore, and measuring and recording at least one characteristic of an interior wall of the enlarged portion of the wellbore. The method further includes expanding cutter blocks of the near-bit reamer and enlarging a portion of the wellbore defined between the expandable reamer and the drill bit, wherein enlarging the portion of the wellbore and measuring and recording the at least one characteristic of the interior wall of the enlarged portion of the wellbore occur in the same trip into the wellbore. 
     Other aspects and advantages of the invention will be apparent from the following description and the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  shows a plan view of an integrated reamer and measurement tool in accordance with one or more embodiments of the present disclosure. 
         FIGS. 2 and 3  show cross-section views of a first expandable reamer in collapsed and expanded positions in accordance with one or more embodiments of the present disclosure. 
         FIG. 4  shows a cross-section view of a near bit reamer in accordance with one or more embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     In one aspect, embodiments disclosed herein relate to an integrated reamer and measurement tool capable of enlarging a wellbore and measuring the enlarged wellbore in a single trip into the wellbore. As used herein, a “trip” is when the entire drillstring is removed from the well to, for example, replace equipment in the drillstring. Referring initially to  FIG. 1 , a plan view of an integrated reamer and measurement tool  100  in accordance with one or more embodiments of the present disclosure is shown. The integrated reamer and measurement tool  100  is attached to a drillstring  102  and includes a selectively expandable reamer  105  having primary cutter blocks  106  coupled with the tool body  100  and located at an axial distance (up to 200 feet) from a drill bit  125  disposed on a distal end thereof. The drill bit  125  may be a roller cone bit or a fixed cutter bit as determined by one of ordinary skill in the art. The integrated tool  100  further includes a selectively expandable near-bit reamer  120  located proximate the drill bit  125  disposed on a distal end thereof and a measurement sub  110  located proximate the expandable reamer  105 , both of which will be described in detail later. 
     Referring briefly to  FIGS. 2 and 3 , cross-section views of the expandable reamer  105  in a collapsed position ( FIG. 2 ) and an expanded position ( FIG. 3 ) in accordance with one or more embodiments of the present disclosure are shown. The expandable reamer  105  includes a generally cylindrical tool body  510  with a flowbore  508  extending therethrough. The tool body  510  includes upper  514  and lower  512  connection portions for connecting the tool  500  into a drilling assembly. In approximately the axial center of the tool body  510 , one or more pocket recesses  516  are formed in the body  510  and spaced apart azimuthally around the circumference of the body  510 . The one or more recesses  516  accommodate the axial movement of several components of the tool  500  that move up or down within the pocket recesses  516 , including one or more movable, non-pivotable, tool arms  520 . Each recess  516  stores one movable arm  520  in the collapsed position. In certain embodiments, the expandable reamer  500  includes three movable arms  520  disposed within three pocket recesses  516 . 
     The recesses  516  further include angled channels  518  that provide a drive mechanism for the movable tool arms  520  to move axially upwardly and radially outwardly into the expanded position shown in  FIG. 3 . A biasing spring  540  may be included to bias the arms  520  to the collapsed position of  FIG. 2 . The biasing spring  540  is disposed within a spring cavity  545  and covered by a spring retainer  550 . Retainer  550  is locked in position by an upper cap  555 . A stop ring  544  is provided at the lower end of the spring  540  to keep the spring  540  in position. 
     Below movable arms  520 , a drive ring  570  is provided that includes one or more nozzles  575 . An actuating piston  530  that forms a piston cavity  535 , engages the drive ring  570 . A drive ring block  572  connects the piston  530  to the drive ring  570  via bolt  574 . The piston  530  is adapted to move axially in the pocket recesses  516 . A lower cap  580  provides a lower stop for the axial movement of the piston  530 . An inner mandrel  560  is the innermost component within the tool  500 , and it slidingly engages a lower retainer  590  at  592 . The lower retainer  590  includes ports  595  that allow drilling fluid to flow from the flowbore  508  into the piston chamber  535  to actuate the piston  530 . 
     The movable arms  520  include pads  522 ,  524 , and  526  with structures  700 ,  800  that engage the wellbore when the arms  520  are expanded outwardly to the expanded position of the tool  500  shown in  FIG. 3 . Below the arms  520 , the piston  530  sealingly engages the inner mandrel  560  at  566 , and sealingly engages the body  510  at  534 . The lower cap  580  is threadingly connected to the body and to the lower retainer  590  at  582 ,  584 , respectively. A sealing engagement is also provided at  586  between the lower cap  580  and the body  510 . The lower cap  580  provides a stop for the piston  530  to control the collapsed diameter of the tool  500 . 
     Several components are provided for assembly rather than for functional purposes. For example, drive ring  570  is coupled to the piston  530 , and then the drive ring block  572  is boltingly connected at  574  to prevent the drive ring  570  and the piston  530  from translating axially relative to one another. The drive ring block  572 , therefore, provides a locking connection between the drive ring  570  and the piston  530 . 
       FIG. 3  depicts the tool  500  with the movable arms  520  in the maximum expanded position, extending radially outwardly from the body  510 . Once the tool  500  is in the wellbore, it is only expandable to one position. Therefore, the tool  500  has two operational positions—namely a collapsed position as shown in  FIG. 2  or an expanded position shown in  FIG. 3 . However, the spring retainer  550 , which is a threaded sleeve, may be adjusted at the surface to limit the full diameter expansion of arms  520 . The spring retainer  550  compresses the biasing spring  540  when the tool  500  is collapsed, and the position of the spring retainer  550  determines the amount of expansion of the arms  520 . The spring retainer  550  is adjusted by a wrench in the wrench slot  554  that rotates the spring retainer  550  axially downwardly or upwardly with respect to the body  510  at threads  551 . The upper cap  555  is also a threaded component that locks the spring retainer  550  once it has been positioned. 
     In the expanded position shown in  FIG. 3 , the arms  520  will either underream the wellbore or stabilize the drilling assembly, depending upon how pads  522 ,  524 , and  526  are configured. In the configuration shown in  FIG. 3 , cutting structures  700  on pads  526  would underream the wellbore. Wear buttons  800  on pads  522  and  524  would provide gauge protection as the underreaming progresses. Hydraulic force causes the arms  520  to expand outwardly to the position shown in  FIG. 3  due to differential pressure of the drilling fluid between the flowbore  508  and the annulus  22 . 
     The drilling fluid flow along path  605 , through ports  595  in the lower retainer  590 , along path  610  into the piston chamber  535 . The differential pressure between the fluid in the flowbore  508  and the fluid in the wellbore annulus  22  surrounding tool  500  causes the piston  530  to move axially upwardly from the position shown in  FIG. 2  to the position shown in  FIG. 3 . A small amount of flow may move through the piston chamber  535  and through nozzles  575  to the annulus  22  as the tool  500  starts to expand. As the piston  530  moves axially upwardly in pocket recesses  516 , the piston  530  engages the drive ring  570 , thereby causing the drive ring  570  to move axially upwardly against the movable arms  520 . The arms  520  will move axially upwardly in pocket recesses  516  and also radially outwardly as the arms  520  travel in channels  518  disposed in the body  510 . In the expanded position, the flow continues along paths  605 ,  610  and out into the annulus  22  through nozzles  575 . Because the nozzles  575  are part of the drive ring  570 , they move axially with the arms  520 . Accordingly, these nozzles  575  are optimally positioned to continuously provide cleaning and cooling to the cutting structures  700  disposed on surface  526  as fluid exits to the annulus  22  along flow path  620 . 
     In certain embodiments, the tool  500  is capable of providing a hydraulic indication at the surface, thereby informing the operator whether the tool is in the contracted position shown in  FIG. 2  or the expanded position shown in  FIG. 3 . Namely, in the contracted position, the flow area within piston chamber  535  is smaller than flow area within piston chamber  535  when the tool  500  is in the expanded position shown in  FIG. 3 . Therefore, in the expanded position, the flow area in chamber  535  is larger, providing a greater flow area between the flowbore  508  and the wellbore annulus  22 . In response, pressure at the surface will decrease as compared to the pressure at the surface when the tool  500  is contracted. This decrease in pressure indicates that the tool  500  is expanded. Additional description of the expandable reamer  500  described herein may be found in U.S. Pat. No. 6,732,817, assigned to the assignee of the present invention, and hereby incorporated by reference in its entirety. In certain embodiments, the tool  500  may include an actuation system as described in U.S. Pat. No. 7,699,120, entitled “On Demand Actuation System” and assigned to the present assignee and incorporated by reference herein in its entirety. Likewise, in other embodiments, the tool  500  may include an actuation system as described in U.S. Patent Publication No. 2010/0006338, entitled “Optimized Reaming System Based Upon Weight on Tool” and assigned to the present assignee and incorporated by reference herein in its entirety. 
     Referring back to  FIG. 1 , and as previously described, the integrated reamer and measurement tool  100  further includes a selectively expandable near-bit reamer  120  located proximate the drill bit  125  disposed on a distal end thereof. As used herein, proximate may be defined as the near-bit underreamer being located substantially near the drill bit. The near-bit underreamer  120  may, for example, be configured as shown in  FIG. 4  in accordance with one or more embodiments of the present disclosure. Referring to  FIG. 4 , drilling assembly  50  is shown having a cutting head  54  located at a distal end of a substantially tubular main body  52 , the body  52  connected to a drillstring (not shown). It should be understood that the term “drillstring” may be used to describe any apparatus or assembly that may be used to thrust and rotate drilling assembly  50 . Particularly, the drillstring may include mud motors, bent subs, rotary steerable systems, drill pipe rotated from the surface, coiled tubing or any other drilling mechanism known to one of ordinary skill. Furthermore, it should be understood that the drillstring may include additional components (e.g., MWD/LWD tools, stabilizers (e.g., expandable and hydraulic), and weighted drill collars, etc.) as needed to perform various downhole tasks. 
     Cutting head  54  is depicted with a cutting structure  58  including a plurality of polycrystalline diamond compact (“PDC”) cutters  60  and fluid nozzles  62 . While drilling assembly  50  depicts a PDC cutting head  54 , it should be understood that any cutting assembly known to one of ordinary skill in the art, including, but not limited to, roller-cone bits and impregnated natural diamond bits, may be used. As drilling assembly  50  is rotated and thrust into the formation, cutters  60  scrape and gouge away at the formation while fluid nozzles  62  cool, lubricate, and wash cuttings away from cutting structure  58 . Tubular main body  52  includes a plurality of axial recesses  64  into which arm assemblies  66  are located. Arm assemblies  66  are configured to extend from a retracted (shown) position to an extended position ( FIG. 3 ) when cutting elements  68  and stabilizer pads  70  of arm assemblies are to be engaged with the formation. 
     Arm assemblies  66  travel from their retracted position to their extended position along a plurality of grooves  72  within the wall of axial recesses  64 . Corresponding grooves along the outer profile of arm assemblies  66  engage grooves  72  and guide arm assemblies  66  as they traverse in and out of axial recesses  64 . While three arm assemblies  66  are depicted in figures of the present disclosure, it should be understood that any number of arm assemblies  66  may be employed, from a single arm assembly  66  to as many arm assemblies  66  as the size and geometry of main body  52  may accommodate. Furthermore, while each arm assembly  66  is depicted with both stabilizer pads  70  and cutting elements  68 , it should be understood that arm assemblies  66  may include stabilizer pads  70 , cutting elements  68 , or a combination thereof in any proportion appropriate for the type of operation to be performed. Additionally, arm assembly  66  may include various sensors, measurement devices, or any other type of equipment desirably retractable and extendable from and against the wellbore upon demand. 
     In operation, cutting structure  58  is designed and sized to cut a pilot bore, or a bore that is large enough to allow drilling assembly  50  in its retracted ( FIG. 1 ) state and remaining components of the drillstring to pass therethrough. In circumstances where the wellbore is to be extended below a string of casing, the geometry and size of cutting structure  58  and main body  52  is such that entire drilling assembly  50  may pass clear of the casing string without becoming stuck. Once clear of the casing string or when a larger diameter wellbore is desired, arm assemblies  66  are extended and cutting elements  68  disposed thereupon (in conjunction with stabilizer pads  70 ) underream the pilot bore to the final gauge diameter. 
     Preferably, drilling assembly  50  uses hydraulic energy to extend arm assemblies  66  from and into axial recesses  64  within main body  52 . Drilling fluid is a necessary component of virtually all drilling operations and is delivered downhole from the surface at elevated pressures through a bore of the drillstring. Similarly, drilling assembly  50  includes a through bore  74 , through which drilling fluids flow through drillstring connection  56  and main body  52  and out fluid nozzles  62  of cutting head  54  to lubricate cutters  60 . As with other downhole drilling devices, the fluid exiting the bore at the bottom of the drillstring returns to the surface along an annulus formed between the wellbore and the outer profile of the drillstring and any tools attached thereto. 
     Because of flow restrictions and differential areas between the bore and the annulus of drillstring components, the annulus return pressure is typically significantly lower than the bore supply pressure. This differential pressure between the bore and annulus is referred to as the pressure drop across the drillstring. Therefore, for every drillstring configuration, a characteristic pressure drop exists that may be measured and monitored at the surface. As such, if leaks in drill pipe connections, changes in the drillstring flowpath, or clogs within fluid pathways emerge, an operator monitoring the drillstring pressure drop from the surface will notice a change and may take action if necessary. 
     Similarly, drilling assembly  50  will desirably exhibit characteristic pressure drop profiles at various stages of operation downhole. When drilling with arm assemblies  66  in their retracted state within axial recesses  64 , drilling assembly  50  will exhibit a pressure drop profile corresponding to that retracted state. When the operator desires to extend arm assemblies  66 , the pressure and/or flow rate of drilling fluids flowing through bore  74  are increased to exceed a predetermined activation level. Once the activation level is exceeded, a flow switch activates a mechanism that will extend arm assemblies  66 . Following such activation, a portion of the drilling fluids are diverted from through bore  74  of main body  52  to the annulus through a plurality of nozzles  76  located adjacent to axial recesses  64 . As drilling fluids begin flowing through nozzles  76 , the characteristic pressure drop of drilling assembly  50  changes to an intermediate profile such that the operator at the surface is aware the flow switch is activated and underreaming has begun. Once arm assemblies  66  are fully extended, drilling assembly  50  is desirably constructed such that additional flow through an indication nozzle ( 77  of  FIG. 3 ) results and another pressure drop profile corresponding to the extended state is exhibited. When the drilling assembly  50  exhibits the expanded characteristic pressure drop profile, an operator monitoring at the surface is aware that arm assemblies  66  have fully extended. Additionally, it is desirable that the intermediate pressure drop profile of drilling fluids remains constant throughout the extension of arm assemblies, such that the surface operator observes a step-plateau change in pressure drop profile for drilling assembly  50 . 
     When retraction of arm assemblies  66  is desired, the operator reduces (or completely cuts off) the pressure and/or flow rate of drilling fluids through bore  74  to a level below a predetermined reset level. Once decreased to the reset level, internal biasing mechanisms retract arm assemblies  66  and shut off flow between bore  74  and nozzles  76  and  77 . Alternatively, the flow of drilling fluids through bore  74  can be cut off altogether. Following retraction, flow through nozzles  76  is halted and the operator may again observe the characteristic pressure drop profile associated with the retracted state across drilling assembly  50  and know that arm assemblies  66  are fully retracted. As with the extension process, an intermediate pressure drop profile will be observed while arm assemblies  66  are in the process of retracting, but not fully retracted. Once the operator observes the “retracted” characteristic pressure drop, they may proceed to raise the pressure and/or flow rate of drilling fluids through drilling assembly  50  up to the activation level without concern for extending arm assemblies  66 . Additional description of the near-bit underreamer  120  described herein may be found in U.S. Pat. No. 7,506,703, assigned to the assignee of the present invention, and hereby incorporated by reference in its entirety. 
     Referring again back to  FIG. 1 , the integrated reamer and measurement tool  100  further includes a measurement sub  110  located proximate the expandable reamer  105 , the measurement sub  110  configured to measure various properties and/or characteristics of an interior wall of the wellbore. The integrated tool  100  further includes a bottomhole assembly  115  that may include measurement-while-drilling or logging-while-drilling equipment. In general, “logging-while-drilling” (“LWD”) refers to measurements related to the formation and its contents. “Measurement-while-drilling” (“MWD”), on the other hand, refers to measurements related to the borehole and the drill bit. The distinction is not germane to the present invention, and any reference to one should not be interpreted to exclude the other. 
     LWD sensors located in measurement sub  110  may include, for example, one or more of a gamma ray tool, a resistivity tool, an NMR tool, a sonic tool, a formation sampling tool, a neutron tool, and electrical tools. Such tools are used to measure properties of the formation and its contents, such as, the formation porosity, density, lithology, dielectric constant, formation layer interfaces, as well as the type, pressure, and permeability of the fluid in the formation. 
     One or more MWD sensors may also be located in measurement sub  110 . MWD sensors may measure the loads acting on the drill string, such as WOB, TOB, and bending moments. It is also desirable to measure the axial, lateral, and torsional vibrations in the drill string. Other MWD sensors may measure the azimuth and inclination of the drill bit, the temperature and pressure of the fluids in the borehole, as well as properties of the drill bit such as bearing temperature and grease pressure. 
     The data collected by LWD/MWD tools is often relayed to the surface before being used. In some cases, the data is simply stored in a memory in the tool and retrieved when the tool it brought back to the surface. Any database for storing data may be used. For example, any commercially available database may be used. In addition, a database may be developed for the particular purpose of storing drilling data. In one embodiment, the remote data store uses a WITSML (Wellsite Information Transfer Standard) data transfer standard. Other transfer standards may also be used in accordance with embodiments disclosed herein. 
     In other cases, LWD/MWD data may be transmitted to the surface using known telemetry methods. The measurement equipment of the measurement sub  110  may be configured to measure and record dimensions of the enlarged wellbore, which may be transmitted to an operator on the surface through an umbilical or other type of data connection (not shown). The data connection may be capable of real-time communication such that data may be transmitted instantaneously. “Real-time” pertains to a data-processing system that controls an ongoing process and delivers its outputs (or controls its inputs) not later than the time when these are needed for effective control. In this disclosure, “in real-time” means that optimized drilling parameters for an upcoming segment of formation to be drilled are determined and returned to a data store at a time not later than when the drill bit drills that segment. The information is available when it is needed. This enables a driller or automated drilling system to control the drilling process in accordance with the optimized parameters. Thus, “real-time” is not intended to require that the process is “instantaneous.” 
     In certain embodiments, the measurement sub  110  may include one or more devices  108  for measuring parameters related to the shape of the interior wall of the wellbore, more commonly called “calipers.” Caliper apparatus and methods generally include sensors disposed in or on components that are configured to be coupled into a drillstring. It may be desirable to have information concerning the shape of the wellbore wall, for example, for calculating cement volume necessary to cement a pipe of casing in the wellbore. It may also be desirable to know the distance between certain types of sensors and the wall of the wellbore, for example, acoustic, neutron and density sensors. Caliper devices known in the art for use in drill strings include acoustic travel time based devices. An acoustic transducer emits an ultrasonic pulse into the drilling fluid in the wellbore, and a travel time to the wellbore wall back to the transducer of the acoustic pulse is used to infer the distance from the transducer to the wellbore wall. In one embodiment, a drillstring caliper may include a tubular body configured to be coupled within a drillstring. At least one laterally extensible arm is housed in the tubular body. A biasing device may be configured to urge the at least one arm into contact with a wall of a wellbore. A sensor may be configured to generate an output signal corresponding to a lateral extent of the at least one arm. 
     A method for measuring an internal size of a wellbore according to certain aspects of the present disclosure includes moving a drill string through a wellbore drilled through subsurface formations. At least one contact arm extending laterally from the drill string is urged into contact with a wall of the wellbore. An amount of lateral extension of the arm is translated into corresponding movement of a sensor to generate a signal corresponding to the amount of lateral extension. The method may include at least one of communicating the signal to the Earth&#39;s surface and recording the signal in a storage device associated with the drill string. 
     In some instances it may be desirable to cause the arms of the caliper to contact the wellbore wall only at certain times or under certain conditions. In such case an actuator may be operable by command from the surface to open or close the caliper upon detection of such command. An example control system may be used to operate the caliper according to different drill string configurations and drilling conditions. The sensor or a plurality of such sensors may be in signal communication with a controller such as a programmable general purpose microprocessor or an application specific integrated circuit. The controller may communicate signals from the sensor to a data storage device, such as a hard drive or solid state memory disposed in the tubular body. The controller may be in signal communication with the telemetry communication channel of wired drill pipe, if such is used as the pipe string or the mud flow modulator for communication of selected signals to the recording unit. 
     In another embodiment, one, two and four caliper arms, typically circumferentially spaced evenly from each other when more than one caliper arm may be used. It should be understood by those skilled in the art that any number of caliper arms structure may be used in accordance with embodiments disclosed herein. The caliper has also been described as being arranged to place the arm(s) in contact with a wall of the wellbore. 
     Methods related to using the integrated measurement and reamer tool described in accordance with one or more embodiments herein include enlarging a main or deviated wellbore with the primary blocks of the expandable reamer. At the same time, the measurement sub located just above the expandable reamer may activate a number of transducers, which measure the expanded diameter of the enlarged wellbore and stores the data on a memory chip or other storage device and/or communicates the data to the surface. The stored data may be downloaded on a laptop or other user interface on the surface (rig) to confirm the enlarged diameter of the wellbore. In alternate embodiments, the measured data may be transmitted immediately in real-time from the measurement sub to a laptop to confirm the enlarged wellbore. 
     Additionally, when the reaming interval of the wellbore is completed, the tool may be pulled up sufficiently so that the near-bit reamer is positioned at the end of the enlarged bore (i.e., just above the rat hole indicated by  55  in  FIG. 1 ). The near-bit reamer is then activated to open and reaming begins until the previously drilled depth is reached, thus enlarging the rat hole similar to the previously reamed interval. Alternatively, when the reaming interval of the wellbore is completed, the near-bit reamer may be activated to open and the tool may be pulled up such that the rat hole is enlarged. In this manner, the rat hole is also enlarged in the same trip as the rest of the wellbore. 
     Advantageously, embodiments of the present disclosure for an integrated measurement and reamer tool allow an operator to achieve a number of goals in a single trip into the wellbore. First, the main bore may be enlarged, next a diameter of the enlarged bore may be confirmed, and finally, the rat hole may be enlarged. The ability to complete a number of different operations in a single trip reduces drilling and rig costs and drilling time and increases productivity and efficiency. 
     While the present disclosure 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 may be devised which do not depart from the scope of the disclosure as described herein. Accordingly, the scope of the disclosure should be limited only by the attached claims.