Patent Publication Number: US-7708067-B2

Title: Apparatus and method for estimating orientation of a liner during drilling of a wellbore

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
   This application takes priority from U.S. Provisional Patent Application Ser. No. 60/969,029, filed on Aug. 30, 2007. 

   BACKGROUND 
   1. Field of the Disclosure 
   This disclosure relates generally to estimating orientation of a liner conveyed in a wellbore and deploying the liner based on such orientation. 
   2. Background of the Art 
   Oil wells (also referred to as “wellbores” or “boreholes”) are typically drilled with a drill string having a drilling assembly (also referred to as a “bottom hole assembly” (BHA)) at the bottom end of a tubular member (such as a jointed pipe or coiled-tubing). A drill bit is attached at the end of drilling assembly to drill the wellbore. Once the wellbore has been drilled, the drill string is retrieved to the surface and a casing is set in the wellbore to avoid a collapse of the wellbore. Such a method requires removing the drill string from the wellbore before deploying and setting the casing in the wellbore. 
   Wellbores are sometimes drilled wherein a liner is placed outside the drill string. The drilling assembly used for such operations includes a drill bit (referred to as the “pilot” bit) to drill a small diameter hole followed by an underreamer (a larger diameter drill bit) which enlarges the pilot hole to a size greater than the outer dimensions of the liner. The drilling assembly is retrievably disposed at or below the liner bottom so that it can be retrieved without retrieving the liner. The liner is set in the wellbore after drilling the wellbore. 
   Many wellbores include sections of different inclinations and curvatures. Some wellbores are further developed by drilling lateral wellbores from the initial or main wellbore. In some cases, it is desirable to form features, such as windows for drilling lateral wellbores, in the liner before it is deployed in the wellbore so as to avoid secondary operations, such as cutting a window in the liner. These and other features can be formed at the surface with greater precision and at a relatively low cost compared to forming such features in the liner after the liner has been deployed in the wellbore. The orientation of the features formed at the surface relative to the drilling assembly or the drill string is known before the deployment of the liner around the drill string. However, due to the relatively long length of the liner and the rotational forces to which it is subjected in the wellbore, the relative location of these features with respect to a known location on the drilling assembly is subject to change. 
   The disclosure herein provides apparatus and methods for estimating orientation of a liner in the wellbore and taking one or more actions based on such estimate. 
   SUMMARY 
   Apparatus and methods for estimating orientation of a liner associated with a drilling assembly are disclosed. An apparatus made according to one embodiment may include a drilling assembly configured for use in drilling a wellbore, a liner disposed outside the drilling assembly, which liner includes a feature at a selected location of the liner, and a liner orientation sensor that provides signals representative of the movement or displacement of the feature relative to the drilling assembly. 
   A method for estimating an orientation of a liner in a wellbore may include: conveying the drill string in the wellbore; providing a liner outside the drill string, the liner including a feature at a selected location of the liner; using an orientation sensor to provide signals representative of a movement or displacement of the feature on the liner relative to the drill string; estimating from the signals the orientation of the feature of the liner. In another aspect, the method may include estimating an orientation of a drilling assembly at the bottom of the drill string and using the estimated orientation of the drilling assembly and the measurement made by the liner orientation sensor to estimate the orientation of the feature. The method may further include setting the liner in the wellbore at least in part based on the estimated orientation of the feature on the liner. 
   Examples of the more important features of the apparatus and methods for estimating orientation of a liner and the deployment of the liner based on such estimation are summarized herein rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions made to the art may be appreciated. There are, of course, additional features of the apparatus and methods that will be described hereinafter and which will form the subject of the claims made pursuant to this application. An abstract is provided herein to satisfy certain regulatory requirements. The summary and the abstract are not intended to limit the scope of any claim made in this application or an application that may take priority from this application. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For detailed understanding of the disclosure, references should be made to the following detailed description, taken in conjunction with the accompanying drawings in which like elements are generally designated by like numerals, and wherein: 
       FIG. 1  is a schematic diagram of a system for drilling a wellbore, which system includes a drilling assembly, an associated liner having a feature and a sensor for providing measurements relating to the movement of the liner feature according to one embodiment of the disclosure; 
       FIG. 2  shows a schematic diagram of an exemplary drilling assembly with a liner placed outside a portion of the drilling assembly and a sensor that may be utilized for estimating the orientation of a feature of the liner; and 
       FIG. 3  shows a schematic diagram of another exemplary drilling assembly with a liner placed around a portion of the drilling assembly and a sensor that may be used for estimating the orientation of a feature of the liner. 
   

   DETAILED DESCRIPTION 
     FIG. 1  is a schematic diagram of a drilling system  100  that utilizes a liner disposed outside a portion of a drill string or drilling assembly for drilling a wellbore according to one embodiment of the disclosure. The drilling system  100  shows a wellbore  110  being formed in a subsurface formation  119  with a drill string  118 . The wellbore  110  is shown to include an upper section  111  that has installed therein a casing  112  and a lower section  114  that is smaller in diameter than the upper section  111  and has no liner therein. The drill string  118  is shown to include a drilling assembly  130  conveyed into the wellbore from the surface  167  by a drilling tubular  116 . The drilling tubular may be a drill pipe made up of jointed drilling pipe sections or a coiled-tubing. The drilling assembly  130  is attached to a bottom end of the drilling tubular  116  by a suitable connector  118   a . A liner  120  is shown deployed outside the drill string  118  and a portion of the drilling assembly  130 . The liner  120  is shown hung in the wellbore  110  via a liner hanger  122  that allows the drill string  118  to pass therethrough. The liner  120  may be detachably coupled to the drilling tubular  116  at a suitable location by a connector  123 . The liner  120  in other embodiments may extend from a location at or below the surface to a location above the drilling assembly  130 . 
   The drill string  118  extends to a rig  180  at the surface  167 . The rig shown herein is a land rig for explanation purposes only. The apparatus and methods disclosed herein may be utilized with an offshore rig or structures used for drilling wellbores under water. A rotary table  169  or a top drive (not shown) may be utilized to rotate the drilling tubular  116 , the drilling assembly  130  and the liner  120 . A reamer unit  160  that includes a reaming drill bit  165  may be deployed at or below the bottom end  121  of the liner  120 . The reamer unit  160  may be detachably attached to the drill string  118  at a suitable location on the drilling assembly  130  above or uphole of the pilot bit  150 . The liner  120  may be of fixed outside dimensions (a non-expandable liner) or it may be a relatively flexible liner that can be expanded while the liner is in the wellbore (an expandable liner). When an expandable liner is used, it may be expanded when the reaming drill bit  165  is pulled out of the wellbore or by another suitable expanding device deployed at or below the bottom end  121  of the liner  120 . Such an expanding device expands the liner  120  when it is retrieved from the wellbore  110 . Expanding the liner places or deploys the liner  120  in the wellbore  110 . 
   In one aspect, the liner  120  may include one or more features (generally denoted by numeral  162 ) that are desired to be oriented in a particular direction when the liner is deployed or placed in the wellbore  110 . A suitable sensor  170  associated with the drilling assembly  118  and the liner  120  is used to estimate or determine the location of the feature  162  relative to the location of a known marker or element in the drilling assembly  120  or the drill string. The sensor  170  provides signals representative of the movement or displacement of the liner feature from a known location on the drilling assembly or the drill string  118 . One or more inclination and orientation sensors  172  (such as accelerometers, magnetometers and gamma ray devices) carried by the drilling assembly  130  provide inclination and orientation of the drilling assembly  130 . A controller  190  at the surface and/or a controller  185  carried by the drilling assembly  118  determines the orientation of the drilling assembly  118  from the orientation sensor  172  measurements and that of the liner feature  162  from the liner orientation sensor  170  measurements. The controller  185  may include a processor  186 , such as a microprocessor, a data storage device  187  for storing therein data and programs  188 . Similarly, the surface controller  190  may be a computer-based system that includes a processor  192 , a data storage device  194  for storing data and programs  196 . The data storage devices  187  and  194  may be any suitable device, including, but not limited to, a read-only memory (ROM), a random-access memory (RAM), a flash memory and a disk. 
     FIG. 2  shows a schematic diagram of an exemplary system  200  containing a drilling assembly  130  with a liner  120  placed around a portion of the drilling assembly. A sensor arrangement or device  260  (also referred to herein as the “liner orientation sensor” or “sensor”) associated with the drilling assembly  130  and the liner  120  may be utilized for estimating the orientation of a feature  263  in the liner  120  when the liner is in the wellbore  110 . The drilling assembly  130  may further include a steering device or mechanism  220  above the pilot drill bit  150 . In one aspect, the steering device  220  may be a closed-loop device or system, which contains a plurality (generally three or more) of independently-controlled force application members, such as members  224   a ,  224   b , etc. Each force application member is configured to apply a desired amount of force on the wellbore wall to steer the pilot bit  150  in a desired direction. The force vector produced by the combination of the forces exerted by the plurality of force application members  242   a ,  242   b , etc. defines the drilling direction. The steering device  220  may include a power unit  272  that supplies power to each of the force application members to independently move each such force application member radially toward the wellbore wall. The power unit  272  may be any suitable device, including, but not limited to, a device wherein a pump supplies fluid under pressure to a piston that moves an associated force application member radially outward or an electric motor that drives a linear member, which in turn moves an associated force application member radially outward. When the drill string  118  is rotated, the pilot bit  150  rotates and drills the lower portion having a first diameter of the wellbore  110 , while the reaming drill bit  262  enlarges the wellbore  110  drilled by the pilot drill bit  150  to a second larger diameter. 
   Still referring to  FIG. 2 , in one aspect, a drilling motor (also referred to as a mud motor or a downhole motor)  268  may be provided in the drilling assembly  130  to rotate the pilot drill bit  150 . The mud motor, in one aspect, superimposes the rotation of drill string  118 . The force application members  242   a ,  242   b , etc. may be activated during the drilling of the wellbore  110  to drill the wellbore along a desired path or trajectory. 
   Still referring to  FIG. 2 , the drilling assembly  130  may also include any number of measurement-while-drilling (MWD) sensors or devices, which are collectively designated herein by numeral  240 . The MWD sensors (or devices)  240  may include any sensor that is useful for obtaining information about the formation  119  surrounding the wellbore  110 . The MWD sensors  240  may include resistivity sensors, acoustic sensors, nuclear sensors, nuclear magnetic resonance sensors, formation testing sensors and any other desired sensors. The drilling assembly  130  also may contain one or more position sensors (generally designated herein by numeral  248 ). The position sensors  248  may be configured to periodically or continuously provide measurements relating to the inclination and orientation of the drilling assembly  130  in the wellbore. Any suitable sensor may be used for providing measurements relating to the inclination and orientation of the drilling assembly  130 , including, but not limited to, accelerometers, magnetometers, and gamma ray devices. The position sensors  248  may provide sufficient measurements to a control unit  170  (see  FIG. 1 ) carried by the drilling assembly  130 , which control unit may calculate or estimate the inclination and orientation of the drilling assembly  130  during drilling of the wellbore  110 . The processor  172  of the control unit  170  accesses the data, computer programs and models and estimates the inclination and orientation of the drilling assembly  130  in the wellbore. The processor  172  may use the measurements made by the sensors  248  and programmed instruction stored in the storage device  174  to calculate the inclination, orientation and position of the drilling assembly  130  in the wellbore. Alternatively, signals from the position sensors  248  may be transmitted to the surface controller  190  for calculating the inclination, orientation and position of the drilling assembly  130 . Further, a combination of the downhole controller  170  and the surface controller  190  may be used to estimate the drill string inclination, orientation and/or position of the drilling assembly. 
   Still referring to  FIG. 2 , the drilling assembly  130  may further include a power unit  272  and a data communication device  274 . The power unit  272  generates power downhole for use by the various sensors and devices associated with the drilling assembly  130 . Any suitable device may be used to generate power downhole, including, but not limited to, a device that utilizes a turbine driven by the circulating drilling fluid in the wellbore  110 . The communication unit  274  provides two-way data communication between the surface devices, such as the controller  190 , and downhole devices, such as the controller  170  and the MWD device  240 . Any suitable telemetry system may be utilized for establishing the two-way communication between the downhole devices and the surface, including but not limited to, a mud pulse telemetry, an acoustic telemetry, an electromagnetic telemetry or a wired-pipe telemetry. Wired-pipe may include communication links, such as electrical conductor or optical fibers that run in or along the drilling string  118 . The telemetry system  274  may also include communication devices that transmit signals across the joints jointed tubulars, including, but not limited to, electrical, electromagnetic and acoustic devices. 
   Still referring to  FIG. 2 , the drilling liner  120  is shown to include a feature  262 , such as a window, that will be used for drilling a lateral wellbore from the wellbore  110  or perforations to allow the flow of the fluid from the formation  119  into the wellbore  110  or any other desired feature. Often, such features are formed in the liner at the surface so as to avoid performing cutting operations after the liner has been placed in the wellbore. For example, it may be desirable to form a window in the liner at the surface to avoid cutting of the window in the liner in the wellbore or to perforate the liner so as to avoid perforating the liner after installation in the wellbore  110 . 
   The system  200  further may include a liner orientation sensor (or sensor)  260 . The sensor  260  is shown to include a sensed element (or first element)  265  associated with or carried by the liner  120  and a sensing element (or second element)  266  carried by the drilling assembly  130 . In one aspect, the liner orientation sensor  260  may be placed proximate the feature, such as feature  263  shown in  FIG. 2 . Any suitable sensor arrangement may be utilized to determine the orientation or relative location of the feature  263  with respect to a location of a known element on the drilling assembly  130 , such as the location of the sensing element  266  or another marker associated with the drilling assembly  130  or the drill string  118 . In one configuration, the liner orientation sensor  260  may include a coil carried by the drilling assembly  130  as the sensing element  266  configured to sense a magnetic field from a magnet (the sensed element  265 ) placed on the liner  120 . In another aspect, the liner orientation sensor  260  may comprise a coded magnetic field as the sensed element  265  on the liner  120  and a coil or detector as the sensing element  266  that senses changes in the coded magnetic field due to changes in the orientation or displacement of the liner  120 . Electrical sensors, acoustic sensors, photoacoustic sensors, etc. also may be utilized for determining the liner orientation. The term movement herein comprises the term displacement. 
   In operation, the liner orientation sensor  260  provides signals representative of the movement or displacement of the feature  263 . The position sensors  248  provide signals relating to the orientation of the drilling assembly  130 . In one aspect, the controller  170  may be configured to process signals from the liner orientation sensor  260  and the position sensors  248  to estimate the orientation of the liner and correlate the determined liner orientation with the orientation of the drilling assembly  130 . Alternatively, signals or processed signals from the liner orientation sensor  260  and/or the position sensors  248  may be sent to the surface controller  190  for estimating the orientation of the feature  263 . Also, both the surface controller  190  and the downhole controller  170  may cooperate to determine the feature orientation. The determined feature orientation may be displayed for use by an operator. The operator may rotate the liner  130  from the surface to align the feature  263  along the desired orientation before setting the liner  130  in the wellbore  110 . The terms estimate and determine are used as synonyms. 
     FIG. 3  shows a schematic diagram of another exemplary drilling assembly  130  with a liner  120  placed around a portion of the drilling assembly  130  and a sensor arrangement  260  that may be used for estimating the orientation of a feature  263  on the liner  120  during drilling of the wellbore  110 . This configuration is similar to that shown in  FIG. 2 , but in this configuration: (i) the drilling motor  268   a  is shown placed below or downhole of the liner orientation sensor  260 , (ii) some of the MWD sensors  248   a  are shown placed below the reamer bit  262  and the remaining MWD sensors  248   b  are shown placed above the reamer bit  262 ; and (iii) and the controller  270   b  are shown placed uphole of the reamer bit  262 . The operations and functions relating to the liner orientation sensor  260  and other devices are the same as described above with respect to  FIG. 2 . 
   Thus, in one aspect, an apparatus for use in a wellbore is disclosed that includes: a drilling assembly configured for use in drilling the wellbore; a liner disposed outside a portion of the drilling assembly that includes a feature at a selected location of the liner; and a liner orientation sensor associated with the liner and the drilling assembly for providing signals representative of the movement of the feature relative to the drilling assembly. The liner orientation sensor may further include a sensed element carried by the liner and a sensing element carried by the drilling assembly, wherein the sensing element generates the signals representative of the movement of the feature with respect to the drilling assembly. In another aspect, the liner orientation sensor may include a magnetic element at a selected location on the liner and a coil proximate the magnetic element on the drilling assembly for providing signals corresponding to a change in the magnetic field generated by the magnetic element. The magnetic element may be: (i) a permanent magnet or (ii) a coded magnetic field on a surface of the liner. The sensing element may be carried by a substantially non-rotating member of the drilling assembly or a rotating member of the drilling assembly. 
   In another aspect, the drilling assembly may further include a drilling assembly orientation sensor for determining the orientation of the drilling assembly in the wellbore. In another aspect, the apparatus may further include a processor that determines the orientation of the feature by utilizing information provided by the liner orientation sensor and the drilling assembly orientation sensor. In another aspect, the apparatus may further include a first drill bit at a bottom end of the drilling assembly for drilling the wellbore of a first diameter and a second drill bit uphole of the first drill for reaming the wellbore of the first diameter to a second larger diameter. In another aspect, the apparatus may include a steering device that contains a plurality of independently-adjustable force application members that are configured to apply force on the wellbore to drill the wellbore along a desired direction. The drilling assembly may rotate relative to the liner or may be non-rotating. 
   In another aspect, a method for estimating orientation of a liner placed outside a drill string during drilling of a wellbore may include: conveying the drill string in the wellbore; providing a liner outside the drilling assembly, the liner having a feature thereon at a selected location of the liner; providing a sensor on the drill string and the liner; taking a measurement by the sensor in the wellbore that is representative of a movement or displacement of the feature on the liner that occurs in the wellbore; processing the measurement to estimate an orientation of the feature in the wellbore. In another aspect, the method may include estimating an orientation of the drilling assembly using the estimated orientation of the drilling assembly and the measurement made by the sensor to estimate the orientation of the feature. 
   The foregoing description is directed to particular embodiments for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiments set forth above are possible without departing from the scope and the spirit of the disclosure. It is intended that any claims relating to this application and any application that takes priority from this application be interpreted to embrace all such modifications and changes. The Summary is provided herein only to aid the reader in understanding certain aspects of the disclosure. The Abstract is provided to satisfy certain regulatory requirements. The embodiments disclosed herein, Summary and Abstract provided herein are not to be used to limit the scope of any claims made in this application or any application that takes priority from this application.