Patent Publication Number: US-11643896-B2

Title: Removing obstructions in a wellbore

Description:
FIELD OF THE DISCLOSURE 
     This disclosure relates to wellbores, in particular, to wellbore tools. 
     BACKGROUND OF THE DISCLOSURE 
     During drilling or production operations, wellbore components or equipment can become stuck in the wellbore due to undesirable circumstances such as differential pressures, equipment failure, or junk piling up. To release the wellbore component, a fishing operation can be performed or solvents can be used to treat the component. Methods and equipment for releasing stuck components are sought. 
     SUMMARY 
     Implementations of the present disclosure include a wellbore assembly that includes a cable configured to be disposed within a wellbore. The wellbore assembly also includes a housing attached to a downhole end of the cable. The housing defines a fluid outlet at a downhole end of the housing. The housing includes an anchor and a collapsible gate. The anchor is coupled to a wall of the housing. The anchor engages a wall of the wellbore under increased tension in the cable, thereby anchoring the housing to the wellbore. The collapsible gate is disposed inside the housing between an uphole end of the housing and the fluid outlet. The housing includes an interior volume defined between the uphole end and the collapsible gate. The housing temporarily stores a treatment fluid configured to treat an obstruction in the wellbore. The collapsible gate is configured to break, with the anchor engaged, under further tension applied by the cable, inside the housing to allow the treatment fluid to flow out of the housing through the fluid outlet toward the obstruction. 
     In some implementations, the housing includes a first housing portion attached to the anchor and a second housing portion movable with respect to and away from the first housing portion. The first housing portion engages the collapsible gate at a first section of the gate and is fixed, with the anchor set on the wellbore, against substantial movement along the wellbore. The second housing portion engages the collapsible gate at a second section of the gate. The second housing section moves, under tension by the cable, with respect to the collapsible gate, thereby breaking the collapsible gate under opposite forces applied at the first and second sections of the collapsible gate. In some implementations, the first housing portion includes an inwardly projecting shoulder configured to engage an edge of the collapsible gate and the second housing portion includes a pin configured to engage the second section of the gate. 
     In some implementations, the housing further includes a biasing member disposed inside the housing. The interior volume is defined between the biasing member and the collapsible gate. The biasing member urges, with the collapsible gate broken, the treatment fluid out of the housing through the fluid outlet toward the obstruction. 
     In some implementations, the housing includes a fish neck sub and a fluid chamber sub attached to a downhole end of the fish neck sub. The fish neck sub houses at least a portion of the biasing member and the fluid chamber houses at least a portion of the treatment fluid pressurized by the biasing member urging the treatment fluid toward the collapsible gate. 
     In some implementations, the housing includes an anchor sub coupled to a downhole end of the fluid chamber. The anchor sub includes the collapsible gate. The anchor sub includes a pin attached to the anchor. The anchor is movable, under a sudden increase of tension in the cable, about the shear pin to engage the wall of the wellbore. In some implementations, the pin is breakable under increased tension in the cable upon depositing the treatment fluid, thereby allowing the anchor to disengage the wall of the wellbore. In some implementations, the fluid chamber sub includes a first shoulder and the anchor sub includes a second shoulder configured to engage, with the collapsible gate broken, the first shoulder, thereby allowing the cable to pull the anchor sub to break the pin and allow the anchor to disengage the wall of the wellbore. 
     In some implementations, the biasing member includes at least one of: an extendable rubber element, a spring, or a piston attached to a plate configured to contact and urge the treatment fluid toward the fluid outlet. The extendable rubber element extends, with the collapsible gate broken, toward the fluid outlet to urge with the plate the treatment fluid out of the housing. 
     In some implementations, the fish neck sub includes a fish neck attached to the cable and a fluid port extending through a wall of the fish neck sub. The fluid port receives fluid configured to increase a pressure of the housing to a pressure above a pressure of the wellbore at or near the obstruction. 
     Implementations of the present disclosure also include a method of assembling a wellbore tool. The method includes obtaining a top sub and a bottom sub. The top sub includes a volume configured to store a treatment fluid and the bottom sub including a collapsible gate, an anchor configured to engage a wall of a wellbore, and a fluid outlet. The method also includes filling at least a portion of the volume of the top sub with the treatment fluid. The method also includes attaching the bottom sub to an end of the top sub such that the fluid is contained between the collapsible gate and an uphole end of the top sub. The method also includes engaging the top sub with the collapsible gate. 
     In some implementations, the top sub includes a threaded end and the bottom sub includes an outer sleeve including a threaded end and an inner sleeve movable with respect to the outer sleeve, and attaching the bottom sub to the top sub includes threadedly attaching the outer sleeve to the top sub such that the inner sleeve is movable with respect to the top sub and the outer sleeve. 
     In some implementations, the method further includes, after attaching the bottom sub to the top sub, pressurizing, through a fluid port of the top sub, the treatment fluid to a pressure above a pressure of a wellbore location at which the wellbore tool is to be deployed. 
     In some implementations, the top sub includes a biasing member disposed inside the top sub, such that the treatment fluid is contained between the collapsible gate and the biasing member with the top sub attached to the bottom sub. The biasing member urges, with the collapsible gate broken, the treatment fluid out the housing through the fluid outlet. 
     In some implementations, the top sub includes a fish neck sub including a fish neck, and a fluid chamber sub including an internal volume configured to store the treatment fluid. Obtaining the top sub includes attaching the fish neck sub to the fluid chamber sub, the fish neck sub configured to house at least a portion of the biasing member and the fluid chamber sub configured to house at least a portion of the treatment fluid. 
     In some implementations, engaging the top sub with the collapsible gate includes engaging, with a pin of the top sub, the collapsible gate such that movement of the top sub with respect to the bottom sub breaks the collapsible gate. 
     Implementations of the present disclosure also include a method of removing an obstruction in a wellbore. The method includes lowering, within a wellbore with a cable, a wellbore tool. The wellbore tool includes 1) a housing, 2) an anchor coupled to a wall of the housing, and 3) a gate disposed inside the housing between an uphole end of the housing and a fluid outlet of the housing. The housing includes an interior volume defined between the uphole end and the collapsible gate and is configured to temporarily store a treatment fluid configured to treat an obstruction in the wellbore and remove the obstruction. The method also includes anchoring, with the anchor, the housing to the wall of the wellbore. The method also includes breaking, by applying tension to the cable, the gate. The method also includes flowing the treatment fluid out of the housing through the fluid outlet toward the obstruction. 
     In some implementations, anchoring the housing includes pulling the cable from a surface of the wellbore, increasing a tension in the housing, and allowing the anchor to move about a pin to engage the wall of the housing. 
     In some implementations, breaking the gate with the cable applying tension to the housing includes pulling the cable to apply tension to the housing. 
     In some implementations, the method further includes disengaging, by applying further tension to the cable, the anchor from the well of the wellbore, wherein disengaging the anchor includes shearing off a pin attached to the anchor. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG.  1    is a schematic front view of a wellbore assembly according to implementations of the present disclosure. 
         FIGS.  2 - 5    are front schematic views, cross-sectional, of sequential steps to remove or dissolve junk in a wellbore using a wellbore assembly according to implementations of the present disclosure. 
         FIG.  6    is a flow chart of an example method of removing junk in a wellbore. 
         FIG.  7    is a flow chart of an example method of assembling a wellbore tool. 
     
    
    
     DETAILED DESCRIPTION OF THE DISCLOSURE 
     The present disclosure describes a wellbore assembly such as an acid dump bailer tool to dissolve junk in a wellbore (e.g., to remove junk and thereby release equipment stuck in the wellbore). The acid dump bailer tool carries acid and dumps the acid on the junk to dissolve the junk and thus improve wellbore operations or release stuck component from the wellbore. The tool is lowered by a cable and operated only by applying tension on the cable (e.g., pulling the cable up the wellbore). Applying tension on the cable anchors the tool and opens a fluid pathway of the tool to dump the acid on the stuck component. 
     Particular implementations of the subject matter described in this specification can be implemented so as to realize one or more of the following advantages. For example, the wellbore assembly of the present disclosure requires minimal or no training. Additionally, the wellbore assembly does not require heavy equipment such as pumps or coiled tubing to send acid to the stuck component. 
       FIG.  1    shows a wellbore assembly  100  (e.g., a wellbore dump assembly) that includes a cable  102  and a housing  104  (e.g., a chamber, a sub, or a wellbore tool) attached to a downhole end of the cable  102 . The cable  102  is disposed within a wellbore  114 . The wellbore  114  is formed in a geologic formation  101  that may include a hydrocarbon reservoir from which hydrocarbons can be extracted. The wellbore  114  extends from a surface  124  (e.g., a ground surface) to a downhole end  188  of the wellbore  114 . The wellbore  114  can be a production wellbore or another type of wellbore. 
     The cable  102  (e.g., a wireline or a slickline) is attached to a surface equipment  112  (e.g., a truck, a crane, or a rig) and lowered by the surface equipment  112  within the wellbore  114 . Lowering the cable  102  lowers the housing  104  within the wellbore  114  to position the housing  104  at a downhole location of the wellbore  114 . 
     An obstruction in the wellbore such as a wellbore component  116  or equipment (e.g., downhole completion nipples, an electric submersible pump, a subsurface safety valve, or wellbore junk) that is stuck in the wellbore  114  can be treated by a treatment fluid contained inside the housing  104  to help release the component  116  from the wellbore For example, during production, a shaft of an electric submersible pump (ESP) can become stuck or jammed in the wellbore  114  due to accumulated impurities  117  such as debris, small fills of heavy oil, or for other reasons such as differential pressures. The wellbore assembly  100  can be lowered to a location near the stuck component  116  to dump a volume of the treatment solution (e.g., an acid, a solvent, or another chemical) to remove the impurities  117  and unstick the component  116  from the wellbore  114 . In some implementations, the treatment solution can be used to clean the wellbore of junk or another obstructions for production or drilling operations. 
     As shown in  FIG.  2   , the housing  104  defines a fluid outlet  105  at a downhole end of the housing  104 . As further described later in detail with respect to  FIG.  4   , the housing  104  allows the treatment fluid ‘F’ to flow out the housing through the fluid outlet  105  to reach the junk or stuck component  116 . 
     The housing  104  includes one or more anchors  130  (e.g., slips) coupled to a wall  107  of the housing  104 . Each anchor  130  has teeth  121  that engage a wall  115  of the wellbore  114  to anchor the housing  104  (e.g., engage the wellbore to prevent substantial movement of the housing) to the wellbore  114 . The anchor  130  is set on the wall  115  of the wellbore  114  under increased tension in the cable  102 . For example, with sudden upward movement of the housing  104  by pulling the cable  102 , the anchors  130  expand or move (e.g., pivot about a pin  139 ) to engage the wall  115  of the wellbore  114 . With the anchor  130  set on the wall  115  of the wellbore  114 , the bottom portion of the wellbore assembly  100  is substantially fixed against movement with respect to the upper portion of the wellbore assembly. 
     The housing  104  also includes a biasing member  108  disposed inside the housing  104  near an uphole end  129  of the housing. The biasing member  108  is attached to a plate  109  that acts as a piston to urge the treatment fluid ‘F’ toward the outlet  105  of the housing  104 . The biasing member  108  can be or include an expandable rubber element  108   a , a spring  108   b , a linear actuator, or a combination of the three. The plate  109  can include an O-ring  110  or another sealing element to form a seal (e.g., a fluid-tight seal) between both sides of the plate  109  (e.g., between an interior volume ‘V’ of the housing and a volume of a fish neck sub  200  where the biasing member  108  is stored). 
     The housing  104  also includes a collapsible gate  111  or disk disposed inside the housing  104  between the biasing member  108  and the fluid outlet  105 . The gate  111  can be made, for example, of ceramic or a similar material that has low fracture toughness or plasticity. The housing  104  has an interior volume ‘V’ defined between the biasing member  108  and the collapsible gate  111  where the treatment fluid ‘F’ is stored. As further described in detail later with respect to  FIG.  4   , after the anchor  130  is set on the wellbore  114 , at least a portion of the housing  104  moves with respect to the collapsible gate  111  to break the gate  111 , allowing the fluid ‘F’ to flow out the housing  104  through the fluid outlet  105 . For example, when the collapsible gate  111  is broken, the rubber element  108   a  extends toward the fluid outlet  105  to urge the treatment fluid out of the housing  104 . 
     The housing  104  can include three subs: 1) a fish neck sub  200  or top sub, 2) a fluid chamber sub  202  or middle sub, and 3) an anchor sub  204  or bottom sub. The fluid chamber sub  202  is coupled to a downhole end of the fish neck sub  202  and the anchor sub  204  is coupled to a downhole end of the fluid chamber sub  202 . To assemble the wellbore assembly  100 , all three subs  200 ,  202 , and  204  can be threadedly attached (e.g., attached at respective threaded ends to form threaded connections  106  and  118 ). The anchor sub  204  can include an outer sleeve  135  that is rotatably locked to the inner sleeve  132 , but slidable (e.g., movable along a common axis) with respect to the inner sleeve  132 . Such configuration allows the anchor sub  204  to be threadedly attached to the middle sub  202 , while still allowing movement of the inner sleeve  132  with respect to the middle sub  202 . Alternatively, the outer sleeve  135  can be rotatable with respect to the inner sleeve  132  and the outer sleeve can have an external tool interface that allows a tool to engage and rotate the outer sleeve  135  to attach the bottom sub  204  to the middle sub  202 . 
     In some implementations, the bottom sub  204  can be referred to as the first portion (e.g., the anchorable or fixable portion) of the housing  104 , and the top sub  200  and the middle sub  202  can be referred to as the second portion (e.g., the movable portion) of the housing  104 . In some implementations, the top and middle sub can be one sub referred to as the top sub. 
     The fish neck sub  200  houses at least a portion of the biasing member  108  and the fluid chamber houses at least a portion of the treatment fluid ‘F’, which is pressurized by the retracted or compressed biasing member  108  urging the treatment fluid toward the collapsible gate  111 . The fish neck sub  200  comprises a fish neck  123  attached to the cable  102  and a fluid port  103  extending through a wall of the fish neck sub  200 . The fluid port  103  (e.g., a pressure equalizing port) receives pressurized fluid (e.g., a pressurized gas or oil) to urge the plate  109  toward the treatment fluid ‘F’, pressurizing the treatment fluid ‘F’. This volume above the plate  109  can be filled with hydraulic oil to raise the pressure in such volume above the formation pressure downhole, to push, with the plate, the treatment fluid ‘F’ out of the housing  104 . 
     The fluid chamber sub  202  includes a fluid port  119  that receives treatment fluid ‘F’ to fill in the volume ‘V’ or pressurize the fluid ‘F’. The volume ‘V’ can store, for example, between 5 to 10 gallons of treatment fluid ‘F’. The fluid chamber sub  202  can include an interior acid-resistant coat to protect the sub  202  from the treatment fluid. The fluid chamber sub  202  can be pressure rated to withstand a pressure of, for example, up to 5,000 psi. The fluid chamber sub  202  is attached to the anchor sub  204  through threaded connection  106 . 
     The anchor sub  204  houses the collapsible gate  111 , but the collapsible gate  111  is attached (or inserted) to a pin  113  of the fluid chamber sub  202 . In some implementations, the anchor sub  204  can include a one-way valve (e.g., a gate valve) disposed between the collapsible gate  111  and the fluid outlet  105  of the housing  104  to prevent fluid from flowing back into the housing  104  after depositing the treatment fluid ‘F’. However, the pressure inside the housing  104  will preferably be greater than the pressure in the wellbore  114 , making the use of a one-way valve unnecessary. As further described in detail below with respect to  FIG.  4   , the anchor sub  204  allows, with the collapsible gate  111  broken, flow of the treatment fluid ‘F’ toward the fluid outlet  105  of the housing  104 . 
     The anchor sub  204  includes a sleeve  132  that is attached, by fasteners  138  and shear-pins  139 , to the anchor  130 . The sleeve  132  has an inwardly projecting shoulder  133  (e.g., a radial shoulder) that engages the collapsible gate  111  to urge the ends of the gate in a downhole direction with respect to the pin  113  unto which the gate  111  is attached. With the anchors  130  set on the wall  115 , further pull of top and middle subs  200  and  202  cause the pin  113  of the middle sub  202  to bend the gate  111  against the shoulder  133  of the anchor sub  204  to collapse the gate  111 . 
       FIGS.  2 - 5    show sequential steps to dump the treatment fluid ‘F’ on the stuck component  116 .  FIG.  2    shows the housing  104  disposed at a downhole location of the wellbore  114 , near the stuck component  116  or junk accumulated in the wellbore. Once the housing  104  is positioned in the desired location, the cable  102  is suddenly pulled upwards toward the surface of the wellbore to activate the anchor  130 . 
     Referring now to  FIG.  3   , pulling the cable  102  in an uphole direction moves or activate the anchors  130  to prevent the anchor sub  130  from moving with respect to the fish neck sub  200  and the second sub  202 . The anchors  130  can pivot or rotate about pin  139  to engage the wall  115  of the wellbore  114 . The sleeve  132  of the bottom sub  204  is attached to the anchors  130  to prevent upward movement of the sleeve  132  when the anchors  130  are set on the wellbore  114 . 
     Referring now to  FIG.  4   , once the anchors  130  are set, the cable  102  is further pulled up to bend the gate between the pin  113  of the middle sub  202  and the shoulders of the bottom sub  204  until the collapsible gate  111  breaks. For example, the pin  113  is fixed to the middle sub  202  and the pin  113  engages the collapsible gate  111  as the middle sub  202  is pulled up by the cable  102 . The middle sub  202  moves upward with respect to the bottom sub  204  because the bottom sub  204  is attached to the wellbore by the anchors  130 .′ The shoulder  133  of the bottom sub  204  prevents the collapsible gate  111  from moving upwards with the pin, thereby bending the gate  111  until the gate  111  collapses. For example, the gate  111  can shatter into pieces to allow the fluid ‘F’ to flow generally uninterruptedly out of the housing  104 . 
     With the collapsible gate  111  broken, the biasing member  108  pushes the fluid ‘F’ out the housing  104  toward the suck component  116  and wellbore junk  117 . The treatment fluid ‘F’ helps dissolve the junk  117  in the wellbore to clean the wellbore or unstuck the wellbore component  116 . 
     Referring now to  FIG.  5   , once the collapsible gate  111  has been broken and the fluid ‘F’ has been deposited in the area of interest, the wellbore assembly  100  can be retracted from the wellbore by further pulling or applying tension on the cable  102 . For example, the sleeve  132  of the bottom sub  204  can engage, with an outwardly projecting shoulder  180  of the sleeve  132 , an inwardly projecting shoulder  181  of the middle sub  202  such that pulling the middle sub  202  applies tension to the bottom sub  204 . Pulling the bottom sub  204  causes the anchors  130  to apply shear stress on the pins  139  until the pins are sheared off. With the pins  139  broken, the anchors  130  retract into position to disengage the wellbore  114 . With the anchors  130  disengaged, the wellbore assembly  100  can be retrieved from the wellbore  114  by pulling on the cable  102 . 
       FIG.  6    shows a flow chart of an example method  600  of removing a wellbore obstruction. The method includes lowering, within a wellbore and with a cable, a housing assembly, the housing assembly comprising 1) an anchor coupled to a wall of the housing, 2) a biasing member disposed inside the housing, and 3) a disk disposed inside the housing between the biasing member and a fluid outlet of the housing and blocking a fluid pathway of the housing, the housing comprising a volume storing a treatment fluid ( 605 ). The method also includes anchoring the housing to the wall of the wellbore ( 610 ), breaking the disk ( 615 ), and flowing the treatment fluid out the fluid outlet toward the stuck component to treat the component ( 620 ). 
       FIG.  7    shows a flow chart of an example method  700  of assembling a wellbore tool. The method includes obtaining a top sub and a bottom sub. The top sub includes a volume configured to store a treatment fluid and the bottom sub includes a collapsible gate, an anchor configured to engage a wall of a wellbore, and a fluid outlet ( 705 ). The method also includes filling at least a portion of the volume of the top sub with the treatment fluid ( 710 ). The method also includes attaching the bottom sub to an end of the top sub such that the fluid is contained between the collapsible gate and an uphole end of the top sub ( 715 ). The method also includes engaging the top sub with the collapsible gate ( 720 ). 
     Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations and alterations to the following details are within the scope and spirit of the disclosure. Accordingly, the exemplary implementations described in the present disclosure and provided in the appended figures are set forth without any loss of generality, and without imposing limitations on the claimed implementations. 
     Although the present implementations have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents. 
     The singular forms “a”, “an” and “the” include plural referents, unless the context clearly dictates otherwise. 
     As used in the present disclosure and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. 
     As used in the present disclosure, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present disclosure.