Patent Publication Number: US-10774603-B2

Title: Hookless hanger for a multilateral wellbore

Description:
TECHNICAL FIELD 
     The present disclosure relates generally to accessing lateral bores in a wellbore, and more particularly (although not necessarily exclusively), to a hookless hanger for a multilateral wellbore. 
     BACKGROUND 
     A well system, such as an oil or gas well for extracting hydrocarbon fluids from a subterranean formation, can include a multilateral wellbore. A liner assembly can be positioned in the wellbore to extend from a main bore into a lateral bore using a whipstock. The whipstock can be removed from the wellbore and cement can be used to secure the liner assembly to the wellbore. The portion of the assembly in the main bore can be drilled or washed out. A whipstock or a deflector can be positioned in the wellbore to guide tools through an inner area of the portion of the remaining liner assembly cemented at a location in the lateral bore. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a cross-sectional diagram of a multilateral wellbore with a hookless hanger assembly according to one aspect of the present disclosure. 
         FIG. 2  is a cross-sectional diagram of a hookless hanger assembly in a main bore of a multilateral wellbore according to one aspect of the present disclosure. 
         FIG. 3  is a cross-sectional diagram of the hookless hanger assembly in  FIG. 2  positioned by a running tool to extend from the main bore into a lateral bore according to one aspect of the present disclosure. 
         FIG. 4  is a cross-sectional diagram of the hookless hanger assembly in  FIG. 2  with the running tool removed to allow for additional tools to be inserted according to one aspect of the present disclosure. 
         FIG. 5  is a cross-sectional diagram of the hookless hanger assembly in  FIG. 2  with a junction isolation tool according to one aspect of the present disclosure. 
         FIG. 6  is a cross-sectional diagram of the hookless hanger assembly in  FIG. 2  with the top liner removed according to one aspect of the present disclosure. 
         FIG. 7  is a flow chart of an example of a process for positioning a hookless hanger assembly in a multilateral wellbore according to one aspect of the present disclosure. 
         FIG. 8  is a flow chart of an example of a process for using a hookless hanger assembly in a multilateral wellbore according to one aspect of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     Certain aspects and features relate to a liner assembly that can be retained at a junction in a multilateral wellbore due to a pivotable connection between an upper tubular body and a lower tubular body of the liner assembly. The upper tubular body can be positioned in a main bore of the multilateral wellbore. The lower tubular body can be pivotally coupled to the upper tubular body at a joint so that the lower tubular body can pivot relative to the upper tubular body and be positioned in a lateral bore of the multilateral wellbore. The upper tubular body is unable to pivot into the lateral bore and can retain the liner assembly at the junction. A deflector can be coupled to an inner surface of the upper tubular body to guide tools into the lower tubular body and the lateral bore. 
     The liner assembly can be positioned in the wellbore using a running tool. The joint and the upper tubular body can remain in the main bore and provide a stopping mechanism for the liner assembly. The lower tubular body can include (or be coupled to) a packer to create a seal between the main bore and the lateral bore to prevent material passing between the outer surface of the lower tubular body and the inner surface of the lateral bore. In some aspects, cement can be positioned radially around the lower tubular body to retain the lower tubular body in the lateral bore and to create a seal between the main bore and the lateral bore. The deflector can be flexible so that the running tool can be removed by compressing the deflector towards the inner surface of the wellbore. 
     In some aspects, the joint (e.g., a hinge pin) between the upper tubular body and the lower tubular body can be dissolved to separate the upper tubular body from the lower tubular body. In some aspects, the joint can be made of a metal (e.g., an aluminum alloy or a magnesium alloy) or a plastic (e.g., polyglycolic acid (“PGA”), polyactic acid (“PLA”), thiol, acrylate, acrylic rubber, polycaprolactone (PCL), polyhydroxyalkonate, and thermoplastic polyurethane (“TPU”)) that dissolves in response to exposure to a specific liquid. In some aspects, the joint can be made of an aliphatic polyester in which the hydrolysable ester bond on the aliphatic polyester can make the material degrade in water. A dissolvable metal alloy (e.g., magnesium or aluminum alloy) may further comprise an amount of dopant material that can increase the galvanic reaction or decrease the growth of protective passivation on the metal alloy. Suitable dopants can include but are not limited to copper, carbon, gallium, tungsten, nickel, iron, copper, indium, zinc, calcium, and tin. The concentration of the dopant can be in an amount from about 0.05% to 25% by weight of the dissolvable metal alloy. The dissolvable metal can be wrought, cast, forged, and/or extruded. The metal can be formed as a solid solution process or as a nano-structured matrix. In some examples, the dissolvable material can be coated with a protective layer to delay the onset of the corrosion. The coating can inhibit the onset of corrosion until the coating is compromised either by mechanically removing the coating, by chemically removing the coating, or by the porosity of the coating allowing degradation of the dissolvable material. The joint can dissolve in response to the acidity of the fluid, the temperature of the fluid, or the chemical composition of the fluid. In some aspects, the joint can dissolve in response to contact with an acid introduced into the wellbore. In additional or alternative aspects, the joint can be made of a degradable alloy that dissolves in response to contact with water, brine, or another fluid naturally present during the life of the wellbore. In some aspects, the liner assembly can enable fracking in the lateral bore. Well fluid from the lateral can flow through the liner assembly from the lower tubular body to the upper tubular body and the well fluids can cause the joint to dissolve. The acid used in the wellbore cleanup or acid stimulation can accelerate the joint dissolving. The upper tubular body can be removed using a spear or other retrieval device coupled to drill pipe or coiled tubing. 
     A hookless hanger can provide a multilateral junction (e.g., a Technology Advancement of MultiLaterals (“TAML”) level 3 or level 4 multilateral junction) for a multilateral wellbore. A hookless hanger can reduce the number of runs needed to complete and perform an operation (e.g., fracking) a lateral bore in a multilateral wellbore. Also, some runs can be performed with coiled tubing rather than drill pipe. A hookless hanger can provide an upper tubular body to form a junction at a casing window. A hookless hanger can also include an integrated deflector for guiding tools or tubing string into the lower tubular body in the lateral bore. A hookless hanger can also have a joint that can dissolve so that the upper tubular body can be removed separate from the lower tubular body to provide an unobstructed main bore. 
     These illustrative examples are given to introduce the reader to the general subject matter discussed here and are not intended to limit the scope of the disclosed concepts. The following sections describe various additional features and examples with reference to the drawings in which like numerals indicate like elements, and directional descriptions are used to describe the illustrative aspects but, like the illustrative aspects, should not be used to limit the present disclosure. 
       FIG. 1  is a cross-sectional diagram of an example of a well system  100  with a liner assembly  130 . The well system  100  can include a wellbore  110  with a main bore  112  and a lateral bore  118 . The main bore  112  can include a casing string  120  and a cement casing  122 . The liner assembly  130  can include an upper tubular body  132  and a lower tubular body  136  pivotally coupled by a hinge pin  134 . 
     The liner assembly  130  can be positioned at a junction in the wellbore  110  between the main bore  112  and the lateral bore  118 . The lower tubular body  136  can pivot relative to the upper tubular body  132  such that the lower tubular body  136  can be positioned in the lateral bore  118  and the upper tubular body  132  can be positioned in the main bore  112 . The upper tubular body  132  and hinge pin  134  can form a stop, to prevent the liner assembly  130  from moving farther into the wellbore  110 . The lower tubular body  136  can be shaped based on an opening between the main bore  112  and the lateral bore  118 . In some aspects, an end of the lower tubular body  136  closest to the main bore  112  is angled such that the end of the lower tubular body  136  is flush with the opening. In additional or alternative aspects, an outer surface of the lower tubular body  136  can include a packer  140  for sealing with the inner surface of the lateral bore  118 . In additional or alternative aspects, cement can be positioned around the outer surface of the lower tubular body  136  to create a seal with the inner surface of the lateral bore  118 . 
     In some aspects, a running tool can be coupled to the liner assembly  130  for positioning the lower tubular body  136  into the lateral bore  118 . The running tool can be detached from the liner assembly  130  and removed from the wellbore  110 . In some aspects, the upper tubular body  132  can have a deflector such that a tool can be inserted into the liner assembly  130  and be guided into the lateral bore  118 . For example, a bow spring or a spring-loaded ramp can be coupled to an inner surface of the upper tubular body  132  such that a junction isolation tool can be guided into the lateral bore  118 . In additional or alternative aspects, the deflector can be flexible such that tools can be removed from the liner assembly  130 . 
     In some aspects, the hinge pin  134  can be dissolved to separate the upper tubular body  132  from the lower tubular body  136 . In some examples, a pivotable connection created by the hinge pin  134  can be created with parts that slideably rotate about an axis. The pivotable connection can also represent a self-locking hinge. In additional or alternative examples, the hinge pin  134  can bend with a flexure. In some aspects, the hinge pin  134  can be made of a material that dissolves in response to exposure to a specific liquid introduced to the wellbore. In additional or alternative aspects, the hinge pin  134  can dissolve in response to contact with fluid naturally present during the installation, completion, stimulation, or production of the wellbore. In some aspects, the liner assembly  130  can enable fracking in the lateral bore  118 . Well fluid from the lateral can flow through the liner assembly  130  from the lower tubular body  136  to the upper tubular body  132 . The well fluids can dissolve the hinge pin  134 . In some aspects, dissolving can include disintegrating, degrading, decomposing, or eroding. In additional or alternative aspects, dissolving can include that the material structurally weakens to the point of losing structural integrity. Dissolving can include any means of degradation including, but not limited to, galvanic degradation, hydrolytic degradation, corrosion, electrochemical degradation, thermal degradation, or combinations thereof. In some examples, dissolving can include complete degradation, in which no solid end products remain after dissolving. In some aspects, the degradation of the material may be sufficient for the mechanical properties of the material to be reduced to a point that the material no longer maintains its integrity. The upper tubular body  132  can be removed separate from the lower tubular body  136  using a retrieval device. In additional or alternative aspects, the upper tubular body  132  can be made of a dissolvable material and dissolve due to exposure to specific fluids. 
     In some aspects, a wellbore can have more than one lateral bore and a liner assembly can be positioned in any number of the lateral bores. In some aspects, a liner assembly can be positioned in an open-hole wellbore. In some aspects, the liner assembly  130  can form a junction between a lateral bore and another bore extending from the lateral bore. Although the liner assembly  130  is described as having an upper tubular body  132  and a lower tubular body  136 , the component of a liner assembly can have any shape. For example, a liner assembly can have an upper oval body and a lower oval body, each with a passage therethrough. 
       FIGS. 2-6  depict a well system  200  with a liner assembly  230 . The well system  200  can include a multilateral wellbore with a main bore  212  and a lateral bore  218 . The liner assembly can include an upper tubular body  232 , a lower tubular body  236 , a hinge pin  234 , a liner string  238 , and a bow spring  240 . The lower tubular body  236  can be pivotally coupled to the upper tubular body by the hinge pin  234 . The liner string  238  can extend from the lower tubular body  236 . The bow spring  240  can be coupled to an inner surface of the upper tubular body  232 . The liner assembly can further include a running tool  250  and a junction isolation tool  260 . In some aspects, the liner assembly can be a hookless hanger system. 
       FIG. 2  is a cross-sectional diagram of the well system  200  with the liner assembly  230  as being positioned in the main bore  212  by a running tool  250 . A longitudinal axis of the upper tubular body  232  is substantially parallel with a longitudinal axis of the lower tubular body  236 . The hinge pin  234  can couple the upper tubular body  232  to the lower tubular body  236 . The running tool  250  can extend through an inner area of the liner assembly  230 . The bow spring  240  can be in a retracted position for limiting interaction with other components (e.g., the running tool  250 ) in the inner area of the liner assembly  230 . In some aspects, the bow spring  240  can be constructed from a dissolvable material. 
       FIG. 3  is a cross-sectional diagram of the well system  200  with the lower tubular body  236  positioned in the lateral bore  218  by the running tool  250 . The liner string  238  couples to the lower tubular body  236  and extends from the lower tubular body  236  into the lateral bore  218 . The lower tubular body  236  is pivoted about the hinge pin  234  such that the lower tubular body extends radially from an end of the upper tubular body  232  positioned in the main bore  212 . 
     Bow spring  240  can be in a retracted position so that the running tool  250  can be removed from the liner assembly  230  without moving the liner assembly  230 . The bow spring  240  can be held in the retracted position. In some aspects, exposure to a specific fluid can allow the bow spring  240  to move to an extended position. In additional or alternative aspects, removal of the running tool  250  from the liner assembly  230  can cause shearing that can allow the bow spring  240  to move to the extended position. 
       FIG. 4  is a cross-sectional diagram of the well system  200  with the running tool  250  removed from the wellbore. The upper tubular body  232  and hinge pin  234  can remain in the main bore  212  and prevent the liner assembly  230  from moving further into the wellbore. The lower tubular body  236  can be positioned in the lateral bore  218  with one end of the lower tubular body  236  flush with an opening between the main bore  212  and the lateral bore  218 . The liner string  238  can be coupled to the lower tubular body  236  and extend into the lateral bore  218 . A cement casing  242  can be positioned around the lower tubular body  236  and the liner string  238  to retain the lower tubular body  236  and the liner string  238  in the lateral bore  218 . 
     In some aspects, bow spring  240  can be coupled to the upper tubular body  232  and can be in an extended position. In the extended position, the bow spring  240  can guide tools inserted into the upper tubular body  232  into the lower tubular body  236  and the lateral bore  218 . For example the bow spring  240  can move between an extended position in which the bow spring  240  can guide a tool into the lateral bore  218  to a retracted position at which the tool can be moved past the bow spring  240  without deflecting the tool. In the extended position, the bow spring  240  extends farther from an inner surface of the upper tubular body  232  than in the retracted position. In some examples, bow spring  240  has a first end coupled to the upper tubular body  232  and a second end that can be slid along the inner surface of the upper tubular body  232  to move between the extended position and the retracted position. 
       FIG. 5  is a cross-sectional diagram of the well system  200  with the junction isolation tool (“JIT”)  260  positioned in the liner assembly  230  such that the JIT  260  extends from the main bore  212  into the lateral bore  218 . The lower tubular body  236  can be pivotally coupled to the upper tubular body  232  at hinge pin  234 . The JIT  260  may have been inserted into the upper tubular body  232  and been guided by bow spring  240  into the lower tubular body  236 . Liner string  238  can be coupled to the lower tubular body  236  and a cement casing  242  can retain the liner string  238  and the lower tubular body  236  in the lateral bore  218 . 
     In some aspects, a fracking operation or an acidizing operation can be performed in the lateral bore  218  by pumping treatment fluid into the lateral bore  218 . The JIT  260  can include a seal assembly  244  and a packer  246  for sealing a junction between the main bore  212  and the lateral bore  218  from fracking pressure. The seal assembly  244  can press into a polished bore in the liner string  238  for the junction from the fracking pressure in the lateral bore  218 . The packer  246  can seal the junction from the fracking pressure in a portion of the main bore  212  that is closer to a surface of the well system  200  than the junction. 
       FIG. 6  is a cross-sectional diagram of the well system  200  after a fracking operation in the lateral bore  218 . The hinge pin  234  may have been dissolved and the upper tubular body  232  may have been dissolved or removed from the wellbore. The liner assembly  230  includes the lower tubular body  236  and the liner string  238 . The lower tubular body  236  can be positioned in the lateral bore  218 . The liner string  238  couples to the lower tubular body  236  and extends from the lower tubular body  236  to a stimulation zone of the lateral bore  218  with fractures  262 . The fractures  262  may be created by pumping a treatment fluid into the stimulation zone using a junction isolation tool. The fractures  262  can allow production fluid to enter the liner string  238 . In some aspects, the production fluid can dissolve the hinge pin  234  or the upper tubular body  232 . In some aspects, the hinge pin  234  can be dissolved to cause the upper tubular body  232  to be separated from the lower tubular body  236 . The upper tubular body  232  can be removed using a rig, or coiled tubing by using an internal catch tool, such as a spear. 
       FIG. 7  is a flow chart of a process for positioning a hookless hanger in a multilateral wellbore. A hookless hanger can provide a multilateral junction (e.g., a TAML level 3 or level 4 multilateral junction) for a multilateral wellbore. A hookless hanger can reduce the number of runs into a wellbore and the cost of each run for accessing a lateral bore. 
     In block  702 , the liner assembly is positioned at a junction in a multilateral wellbore. The liner assembly having a lower tubular body pivotally coupled to an upper tubular body at a joint. The liner assembly can be positioned such that the upper tubular body is radially adjacent to an opening between the main bore and the lateral bore. 
     In block  704 , the lower tubular body is pivoted about the joint to position the lower tubular body in a lateral bore and the upper tubular body in a main bore. The lower tubular body can be shaped based on an opening between the main bore and the lateral bore. In some aspects, an end of the lower tubular body closest to the main bore is angled such that the end of the lower tubular body is flush with the opening. In block  706 , cement is positioned around the lower tubular body and the liner string. The cement can retain the lower tubular body at a location in the lateral bore and form a seal between the main bore and the lateral bore. In some aspects, the lower tubular body can be retained in the lateral bore without using cement. For example, the upper tubular body and joint can form a stop, preventing the liner assembly from moving farther into the wellbore. 
     In block  708 , the running tool is allowed to be removed from the liner assembly. In some aspects, a deflector (e.g., a bow spring or a spring-loaded ramp) can be coupled to an inner surface of the upper tubular body. In some aspects, a bow spring can be in a retracted position so that the running tool can be removed from the liner assembly without moving the liner assembly. The bow spring can be held in the retracted position and can move to an extended position in response to exposure to a specific fluid. In additional or alternative aspects, the bow spring can move to an extended device in response to shearing during removal of the running tool from the liner assembly. 
     In block  710 , an additional tool is guided to the lateral bore. The deflector can be in the extended position to guide the additional tool from the upper tubular body to the lower tubular body and the lateral bore. 
       FIG. 8  is a flow chart of a process for using a hookless hanger in a multilateral wellbore. In some aspects, the main bore can be left unobstructed after an operation is performed in the lateral bore. 
     In block  802 , treatment fluid (e.g., fracking fluid) is allowed to enter the lateral bore through tubing positioned in an inner area of an upper tubular body and an inner area of a lower tubular body. The treatment fluid can stimulate the portion of the lower tubular body creating fractures or removing blockages to improve production of well fluid. In block  804 , the tubing is removed from assembly. The diverter can be flexible to allow the tubing to pass thereby through the liner assembly. 
     In block  806 , a joint pivotally couples the upper tubular body to the lower tubular body is dissolved. In some aspects, the joint (e.g., a hinge pin) can be dissolved to separate the upper tubular body from the lower tubular body. In some aspects, the joint can dissolve in response to an acidity of the fluid, a temperature of the fluid, or a chemical composition of the fluid. The joint may dissolve in response to being exposed to well fluid from flowing through the liner assembly from the lower tubular body to the upper tubular body. 
     In block  808 , the upper tubular body having a deflector is removed from the wellbore. The upper tubular body can be removed separate from the lower tubular body using a spear or other retrieval device coupled to drill pipe or coiled tubing. In some aspects, the upper tubular body and deflector can be dissolved. 
     In some aspects, a hookless hanger for a multilateral wellbore is provided according to one or more of the following examples: 
     Example #1 
     An assembly can include an upper tubular body and a lower tubular body. The upper tubular body can be positioned in a main bore of a wellbore. The lower tubular body can be pivotally coupled to the upper tubular body at a joint to allow the lower tubular body to pivot relative to the upper tubular body. The lower tubular body can be positioned in a lateral bore of the wellbore. 
     Example #2 
     The assembly of Example #1, can feature the joint dissolved such that the upper tubular body can be separated from the lower tubular body. The upper tubular body can be removed from the wellbore while the lower tubular body is positioned in the lateral bore. 
     Example #3 
     The assembly of Example #2, can feature the joint being dissolved in response to contact with fluid naturally present in the wellbore. 
     Example #4 
     The assembly of Example #2, can feature the joint being a hinge pin made of magnesium alloy. The hinge pin can be dissolved in response to contact with an acid introduced into the wellbore. 
     Example #5 
     The assembly of Example #1, can further include a deflector coupled to an inner surface of the upper tubular body. The deflector can be for guiding a tool from an inner area of the upper tubular body into the lower tubular body and the lateral bore. 
     Example #6 
     The assembly of Example #5, can feature the deflector being a bow spring that is moveable between an extended position for guiding the tool into the lateral bore and a retracted position for allowing the tool to be removed from the assembly. 
     Example #7 
     The assembly of Example #5, can feature the deflector being a spring-loaded ramp that is moveable between an extended position for guiding the tool into the lateral bore and a retracted position for allowing the tool to be removed from the assembly. 
     Example #8 
     The assembly of Example #5, can feature the upper tubular body and the deflector being dissolved. 
     Example #9 
     The assembly of Example #1, can feature the upper tubular body and the lower tubular body being positioned in the wellbore by a running tool. The running tool can extend through the upper tubular body and the lower tubular body and can be removed from the assembly. 
     Example #10 
     A system including an upper tubular body, a lower tubular body, and a running tool. The lower tubular body can be pivotally coupled to the upper tubular body at a joint to form a liner assembly and to allow the lower tubular body to pivot relative to the upper tubular body. The running tool can be positioned in the liner assembly to position the liner assembly at a junction in a wellbore between a main bore and a lateral bore. The running tool can position the upper tubular body in the main bore and the lower tubular body in the lateral bore. 
     Example #11 
     The system of Example #10, can feature the joint being dissolved to allow the upper tubular body to be separated from the lower tubular body and removed from the wellbore. 
     Example #12 
     The system of Example #10, can further include a deflector coupled to an inner surface of the upper tubular body for guiding an additional tool into the lateral bore. The upper tubular body and the deflector can be dissolved. 
     Example #13 
     The system of Example #12, can feature the deflector moving between a retracted position for allowing the running tool or the additional tool to be removed from an inner area of the liner assembly and an extended position for guiding the additional tool through the liner assembly and into the lateral bore. 
     Example #14 
     The system of Example #10, can feature the lower tubular body being fixable in the lateral bore by cement. 
     Example #15 
     A method can include positioning a liner assembly at a junction in a multilateral wellbore by a running tool. The liner assembly can have a lower tubular body pivotally coupled to an upper tubular body at a joint. The method can further include rotating the lower tubular body about the joint such that the lower tubular body is positioned in a lateral bore of the multilateral wellbore and the upper tubular body is positioned in a main bore of the multilateral wellbore. The method can further include guiding an additional tool into the lateral bore by a deflector. The deflector can be coupled to an inner area of the upper tubular body for deflecting the additional tool through the lower tubular body and into the lower tubular body after removing the running tool from the liner assembly. 
     Example #16 
     The method of Example #15, can further include dissolving the joint such that the upper tubular body is separated from the lower tubular body. 
     Example #17 
     The method of Example #16, can further include removing the upper tubular body and the deflector from the multilateral wellbore with the lower tubular body remaining in the lateral bore. 
     Example #18 
     The method of Example #15, can further include dissolving the upper tubular body and the deflector such that the liner assembly is flush with a window between the lateral bore and the main bore and the liner assembly extends from the window into the lateral bore. 
     Example #19 
     The method of Example #15, can feature the additional tool being a junction isolation tool for isolating a portion of the lateral bore from the main bore. The method can further include allowing fracking fluid to move through the liner assembly into the portion of the lateral bore for stimulating a subterranean formation. 
     Example #20 
     The method of Example #15, can feature removing the running tool as including moving the deflector from a retracted position for allowing the running tool or the additional tool to pass thereby to an extended position for guiding the additional tool into the lateral bore. 
     The foregoing description of certain examples, including illustrated examples, has been presented only for the purpose of illustration and description and is not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Numerous modifications, adaptations, and uses thereof will be apparent to those skilled in the art without departing from the scope of the disclosure.