Patent Document

CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. provisional patent application Ser. No. 61/712,859, filed Oct. 12, 2012, which is herein incorporated by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to a wellbore operation. More particularly, embodiments of the present invention relate to a packer cup for sealing a wellbore. 
     2. Description of the Related Art 
     During a wellbore operation, it is necessary to isolate one portion of the wellbore from another a portion of the wellbore. The device that is used to isolate the wellbore portion is called a packer cup. The conventional packer cup includes a back-up ring attached to a rubber member. However, the conventional packer cup has a limited acceptable range for sealing applications inside an eccentric wellbore and an off-center packer cup application due to the design of the back-up ring and the rubber member. Therefore, there is a need for a packer cup for creating a seal in the eccentric wellbore and the off-center packer cup application. 
     SUMMARY OF THE INVENTION 
     The present invention generally relates to a packer for creating a seal in an annular area. In one aspect, a packer cup for use in a wellbore is provided. The packer cup includes a base and a first seal segment having a first end and a second end. The first end of the first seal segment is attached to the base. The packer cup further includes a second seal segment that is spaced apart from the base. The second seal segment is attached to the second end of the first seal segment, wherein each seal segment is configured to move from a retracted shape to an expanded shape upon activation of the respective seal segment. 
     In another aspect, a method for creating a seal between a tubular and a wellbore is provided. The method includes the step of positioning a packer cup in the wellbore. The packer cup has a first seal segment attached to a base and a second seal segment spaced apart from the base, and attached to the first seal segment. The method further includes the step of activating the seal segments, which causes each seal segment to move from a retracted shape to an expanded shape. Additionally, the method includes the step of creating the seal between the tubular and the wellbore as the seal segments engage the wellbore in the expanded shape. 
     In a further aspect, a packer is provided. The packer includes a base configured to be attached to a tubular. The packer further includes a first seal segment having a first end and a second end. The first end of the first seal segment is attached to the base. The packer also includes a second seal segment that is spaced apart from the base. The second seal segment is attached to the second end of the first seal segment. Additionally, the packer includes a third seal segment that is spaced apart from the base. The second seal segment is attached to an end of the second seal segment, wherein each seal segment has a different outer diameter. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention, and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  is a view of a packer cup disposed in a wellbore. 
         FIGS. 2 and 2A  illustrate a view of the packer cup in a run-in position. 
         FIGS. 3 and 3A  illustrate a view of the packer cup in an intermediate expanded position. 
         FIGS. 4 and 4A  illustrate a view of the packer cup in an expanded position. 
         FIG. 5  illustrates a view of a packer cup. 
         FIG. 6  illustrates a view of a packer cup. 
         FIGS. 7 and 7A  illustrate a view of the packer cup in a run-in position. 
         FIGS. 8 and 8A  illustrate a view of the packer cup in an intermediate expanded position. 
         FIGS. 9 and 9A  illustrate a view of the packer cup in an expanded position. 
         FIG. 10  illustrates a view of a packer cup. 
         FIG. 11  illustrates a view of a packer cup. 
         FIG. 12  illustrates a view of a packer cup in an eccentric wellbore. 
         FIG. 13  illustrates a view of a packer cup in an eccentric wellbore. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention generally relates to a packer cup for sealing a wellbore. The packer cup will be described herein in relation to pipe that is used in the wellbore. It is to be understood, however, that the packer cup may also be used with other downhole tools, such as a whipstock seal, or a debris barrier, without departing from principles of the present invention. Further, the packer cup may be used in a cased wellbore or within an open-hole wellbore. To better understand the novelty of the packer cup of the present invention and the methods of use thereof, reference is hereafter made to the accompanying drawings. 
       FIG. 1  is a view of a packer cup  100  disposed in a wellbore  40 . The packer cup  100  is used to isolate a defect  70  in the wellbore  40 . The packer cup  100  is attached to a workstring  20 . As shown in  FIG. 1 , a casing  10  is disposed in the wellbore  40 . The casing  10  may be cemented in the wellbore  40  using cement  30  and may include multiple sections of casings coupled together to form the casing  10 . 
     Located along the length of the casing  10  is the defect  70 , such as a leaking connection or a fracture in the wall of the casing  10 . The defect  70  may permit the loss of a fluid, such as a liquid or a gas, into the surrounding earthen formation or permit the introduction of unwanted fluids into the casing  10  of the wellbore  40 . As a result, dangerous pressure fluctuations may occur during the formation or completion of the wellbore  40 . To isolate the defect  70 , one or more packer cups  100  are used. As shown in  FIG. 1 , two packer cups  100  are used to isolate a first portion  185 A of the wellbore  40  from a second portion  185 B of the wellbore  40 . The first portion  185 A has a pressure P1 that is greater than a pressure P2 in the second portion  185 B of the wellbore  40 . Generally, the opening of the packer cup  100  is facing the portion of the wellbore having the higher pressure (as shown). As will be described herein, the pressure (e.g., pressure P1) adjacent the packer cup  100  will be used to set the packer cup  100  in the wellbore  40 . 
     As shown in  FIG. 1 , the workstring  20  is not centered in the casing  10 . In other words, a longitudinal axis of the workstring  20  is offset from a longitudinal axis of the casing  10 . As a result, distance  130  is greater than distance  135 . Generally, a workstring in a horizontal wellbore may sag, which causes the packer cup  100  to be off-center in the casing  10 . The conventional packer cup may not be able to create a seal with the casing when the conventional packer cup is off-center in the casing. However, the packer cup  100  of the present invention is configured to create a seal with the casing, even if the packer cup  100  is off-center, or if the packer cup  100  is placed within an eccentric casing (or wellbore). 
       FIGS. 2 and 2A  illustrate a view of the packer cup  100  in a run-in position. As shown, the packer cup  100  includes a base  105  with a lip  110  and seal segments  160 ,  170 ,  180 . The seal segments  160 ,  170 ,  180  are interconnected together. In one embodiment, the seal segments  160 ,  170 ,  180  are separate pieces (and/or material) that are attached together by bonding, glue or another attachment method. In another embodiment, the seal segments  160 ,  170 ,  180  are formed from a single piece. In either case, the seal segments  160 ,  170 ,  180  are designed to engage and create a seal with the casing  10  upon activation of the packer cup  100 . The packer cup  100  in  FIG. 2  shows three seal segments, however, two or more seal segments may be used in the packer cup  100  without departing from principles of the present invention. The seal segments  160 ,  170 ,  180  are connected to the base  110 . As shown, a portion of the seal segment  160  is disposed under the lip  110 . The base  105  is configured to be attached to the workstring  20  by a connection member  115 , such as threads, key and groove arrangement or any other type of connection member. A seal member (not shown) may be placed between the base  105  and the workstring  30  to create a seal therebetween. As also shown, an annulus  175  is defined between an outer surface of the workstring  20  and an inner surface of the seal segments  160 ,  170 ,  180 . 
     The seal segments  160 ,  170 ,  180  are configured to seal an annulus between the workstring  20  and the casing  10 . The seal segments  160 ,  170 ,  180  are configured to move between a retracted shape ( FIG. 2 ) and an expanded shape ( FIG. 4 ). Each seal segment  160 ,  170 ,  180  is an annular member that is made of a flexible material, such as elastomer or plastic. In the embodiment shown, each seal segment  160 ,  170 ,  180  has a different outer diameter (OD). The OD of seal segment  160 &lt;the OD of seal segment  170 &lt;the OD of seal segment  180 . As shown, a gap  140  is formed between seal segment  160  and the casing  10 , and a smaller gap  190  is formed between seal segment  170  and the casing  10 . Additionally, a gap  195  is formed between the lip  110  and the casing  10 . 
     The packer cup  100  is off-center in the casing  10 . As shown in  FIG. 2 , the upper portions  160 A,  170 A of the seal segments  160 ,  170  are not in contact with the casing  10 , while the lower portions  160 B,  170 B,  180 B of the seal segments  160 ,  170 ,  180  are in contact with the casing  10 . Additionally, the upper portion  110 A of the lip  110  is not in contact with the casing  10 , while the lower portion  1108  of the lip  110  is in contact with the casing  10 . 
       FIG. 2A  is a sectional view along line  2 A- 2 A in  FIG. 2 . As shown, the gap  140  is formed between seal segment  160  and the casing  10 , because the workstring  20  is offset relative to the casing  10  (distance  130 &gt;distance  135 ) and the OD of seal segment  160 . As also shown, the thickness of the upper portion  160 A of seal segment  160  and the lower portion  1608  of seal segment  160  have substantially the same thickness in the run-in position. 
       FIGS. 3 and 3A  illustrate a view of the packer cup  100  in an intermediate expanded position. After the packer cup  100  is positioned within the casing  10 , pressure P1 activates the packer cup  100  in order to isolate a portion of the wellbore. More specifically, the pressure P1 enters an opening  120  of the packer cup  100  and moves into the annulus  175 , which causes the seal segments  160 ,  170 ,  180  to expand radially outward toward the casing  10 . The seal segments  160 ,  170 ,  180  are made from a flexible material, and since pressure P1 is greater than P2, the seal segments  160 ,  170 ,  180  are urged radially outward. In comparing  FIG. 3  (intermediate expanded position) and  FIG. 2  (run-in position), it can be seen that the upper portions of the seal segments  160 A,  170 A,  180 A are in contact with the casing  10 , which results in the gaps  140  and  190  being substantially closed. It can also be seen that the lower portions of the seal segments  160 B,  170 B,  180 B have more surface area in contact with the casing  10  in the intermediate expanded position. It can be further seen that the gap  195  between the upper lip  110 A and the casing  10  is still present in the intermediate expanded position. 
       FIG. 3A  is a sectional view along line  3 A- 3 A in  FIG. 3 . As shown, the gap  140  formed between seal segment  160  and the casing  10  has been closed due to the activation of the packer cup  100 . It is to be noted that the workstring  20  remains offset relative to the casing  10  (distance  130 &gt;distance  135 ). 
       FIGS. 4 and 4A  illustrate a view of the packer cup  100  in an expanded position. The packer cup  100  has been expanded by the pressure P1 in the annulus  175 . In comparing  FIG. 4  (expanded position) and  FIG. 3  (intermediate expanded position), it can be seen that the upper portions of the seal segments  160 A,  170 A,  180 A and the lower portions of the seal segments  160 B,  170 B,  180 B have more surface area in contact with the casing  10 . It can also be seen that the gap  195  between the upper lip  110 A and the casing  10  has been closed, and the upper lip  110 A and the lower lip  1108  are in contact with casing  10 . In one embodiment, the lip  110  may act as a barrier to the flow of the material of the seal segments  160 ,  170 ,  180 . In this manner, the lip  110  in the packer cup  100  may act as an anti-extrusion device or an extrusion barrier. In another embodiment, the lip  110  may act as an anchor portion that secures the packer cup  100  in the casing  10 . 
       FIG. 4A  is a sectional view along line  4 A- 4 A in  FIG. 4 . As shown, the gap  140  formed between seal segment  160  and the casing  10  is closed due to the activation of the packer cup  100 . As also shown, the thickness of the upper portion  160 A of seal segment  160  is smaller than the thickness of the lower portion  160 B of seal segment  160 , because the upper portion  160 A was radially expanded further relative to the centerline of the packer cup  100  than the lower portion  160 B, due to the packer cup  100  being off-center in the casing  10 . In this manner, the packer cup  100  is capable of sealing an annulus between the casing  10  and the string  20 , even with the packer cup  100  being off-center in the casing  10 . 
       FIG. 5  illustrates a view of a packer cup  200 . For convenience, the components in the packer cup  200  that are similar to the components in the packer cup  100  will be labeled with the same number indicator. The packer cup  200  includes seal segments  210 ,  220 ,  230  and the base  105 . The seal segments  210 ,  220 ,  230  are interconnected together. The seal segments  210 ,  220 ,  230  may be separate pieces (and/or material) that are attached together, or the seal segments  210 ,  220 ,  230  may be formed from a single piece. In either case, the seal segments  210 ,  220 ,  230  are designed to engage and create a seal with the casing (not shown) upon activation of the packer cup  200 . Each seal segment  210 ,  220 ,  230  may have a different outer diameter (OD). For instance, the OD of seal segment  210  may be less than the OD of seal segment  220 , which may be less than the OD of seal segment  230 . Further, each seal segment  210 ,  220 ,  230  may have a different longitudinal length. For instance, the length of seal segment  220  may be shorter than the length of seal segment  230 , which may be shorter than the length of seal segment  210 . Additionally, the thickness of the seal segments  210 ,  220 ,  230  may be different. Each characteristic (e.g., diameter, length, thickness, number of seal segments) of the seal segment  210 ,  220 ,  230  may be selected based upon the application in the wellbore. 
       FIG. 6  illustrates a view of a packer cup  250 . For convenience, the components in the packer cup  250  that are similar to the components in the packer cup  100  will be labeled with the same number indicator. The packer cup  250  includes seal segments  260 ,  270 ,  280  and the base  105 . The seal segments  260 ,  270 ,  280  are interconnected together. In one embodiment, the seal segments  260 ,  270 ,  280  may be made from different material, such as a rubber material having a different durometer. The seal segments  260 ,  270 ,  280  may be attached together to form a single unit of seal segments. In another embodiment, the seal segments  260 ,  270 ,  280  may be made from the same material and attached together or formed from a single piece. Similar to the other packer cups set forth herein, the seal segments  260 ,  270 ,  280  are designed to engage and create a seal with the casing (not shown) upon activation of the packer cup  250 . In the embodiment shown in  FIG. 6 , each seal segment  260 ,  270 ,  280  has several different diameters. For example, each seal segment  260 ,  270 ,  280  has a first diameter  255 , a second diameter  265 , a third diameter  275 , and a fourth diameter  285 . The alternating large diameter sections and small diameter sections create a redundancy that allows the packer cup  250  to create a seal with the casing (or wellbore), even if the packer cup  250  is off-center, or if the packer cup  250  is placed within an eccentric casing (or wellbore). Further, each seal segment  260 ,  270 ,  280  may have the same or different longitudinal length. Additionally, each seal segment  260 ,  270 ,  280  may have the same or different thickness. Each characteristic (e.g., diameter, length, thickness, number of seal segments) of the seal segment  260 ,  270 ,  280  may be selected based upon the application in the wellbore. 
       FIGS. 7 and 7A  illustrate a view of the packer cup  300  in a run-in position. For convenience, the components in the packer cup  300  that are similar to the components in the packer cup  100  will be labeled with the same number indicator. As shown, the packer cup  300  includes seal segments  360 ,  370 ,  380 , which are attached to the base  105 . The seal segments  360 ,  370 ,  380  are interconnected together to form a single unit. In one embodiment, the seal segments  360 ,  370 ,  380  are separate pieces (and/or material) that are attached together by bonding, glue or another attachment method. In another embodiment, the seal segments  360 ,  370 ,  380  are formed from a single piece. The seal segments  360 ,  370 ,  380  are designed to engage and create a seal with the casing  10  upon activation of the packer cup  300 . Even though the packer cup  300  is illustrated with three seal segments, the packer cup  300  may include two or more seal segments without departing from principles of the present invention. An annulus  375  is defined between an outer surface of the workstring  20  and an inner surface of the seal segments  360 ,  370 ,  380 . 
     The seal segments  360 ,  370 ,  380  are configured to create a seal between the workstring  20  and the casing  10 . The seal segments  360 ,  370 ,  380  are configured to move between a retracted shape ( FIG. 7 ) and an expanded shape ( FIG. 9 ). Each seal segment  360 ,  370 ,  380  is an annular member that is made of a flexible material, such that the seal segments  360 ,  370 ,  380  deform upon application of a pressure. In the embodiment shown, each seal segment  360 ,  370 ,  380  has substantially the same outer diameter (OD). 
     The packer cup  100  is substantially centered in the casing  10 . In other words, distance  330  is substantially equal to distance  335 . As shown  FIG. 7 , upper portions  360 A,  370 A,  380 A of the seal segments  360 ,  370 ,  380  and the lower portions  360 B,  370 B,  380 B of the seal segments  360 ,  370 ,  380  are in contact with the casing  10 . Additionally, the upper portion  110 A and lower portion  1108  of the lip  110  are not in contact with the casing  10 . 
       FIG. 7A  is a sectional view along line  7 A- 7 A in  FIG. 7 . As shown, the entire section of seal segment  360  is engaged with the casing  10  because the workstring  20  is substantially centered in the casing  10  (distance  330  is substantially equal to distance  335 ) and the OD of seal segment  360 . As also shown, the upper portion  360 A of seal segment  360  and the lower portion  360 B of seal segment  360  have substantially the same thickness in the run-in position. 
       FIGS. 8 and 8A  illustrate a view of the packer cup  300  in an intermediate expanded position. After the packer cup  300  is positioned within the casing  10 , pressure P1 activates the packer cup  300  in order to isolate a portion of the wellbore. More specifically, the pressure P1 enters an opening  320  of the packer cup  330  and moves into the annulus  375 , which causes the seal segments  360 ,  370 ,  380  to expand radially outward toward the casing  10 . The seal segments  360 ,  370 ,  380  are made from a flexible material, and since pressure P1 is greater than pressure P2, the seal segments  360 ,  370 ,  380  are urged radially outward. In comparing  FIG. 8  (intermediate expanded position) and  FIG. 7  (run-in position), it can be seen that the upper portions  360 A,  370 A,  380 A and the lower portions  360 B,  370 B,  380 B of the seal segments have been expanded radially outward into further contact with the surrounding casing  10 . It can be further seen that the gap  395  between the lips  110 A,  1108  and the casing  10  is still present in the intermediate expanded position. 
       FIG. 8A  is a sectional view along line  8 A- 8 A in  FIG. 8 . As shown, the workstring  20  remains substantially centered relative to the casing  10  (distance  330  is substantially equal to distance  335 ). As also shown, the upper portion  360 A of seal segment  360  and the lower portion  360 B of seal segment  360  have substantially the same thickness in the intermediate expanded position. 
       FIGS. 9 and 9A  illustrate a view of the packer cup  300  in an expanded position. The packer cup  300  has been expanded by the pressure P1 in the annulus  375 . In comparing  FIG. 9  (expanded position) and  FIG. 8  (intermediate expanded position), it can be seen that the upper portions  360 A,  370 A,  380 A and the lower portions  360 B,  370 B,  380 B of the seal segments have more surface area in contact with the casing  10 . It can also be seen that the gap  195  has been closed, and the upper lip  110 A and the lower lip  1108  are in contact with casing  10 . In one embodiment, the lip  110  may act as a barrier to the flow of the material of the seal segments  360 ,  370 ,  380 . In this manner, the lip  110  in the packer cup  300  may act as an anti-extrusion device or an extrusion barrier. In another embodiment, the lip  110  may also act as an anchor portion that secures the packer cup  300  in the casing  10 . 
       FIG. 9A  is a sectional view along line  9 A- 9 A in  FIG. 9 . As shown, the thickness of the upper portion  360 A of seal segment  360  is substantially equal to the thickness of the lower portion  360 B of seal segment  360  because the portions  360 A,  360 B were radially expanded the same amount due to the packer cup  300  being centered in the casing  10 . In this manner, the packer cup  300  is capable of sealing an annulus between the casing  10  and the string  20  when the packer cup  300  is centered in the casing  10 . 
       FIG. 10  illustrates a view of a packer cup  400 . For convenience, the components in the packer cup  400  that are similar to the components in the packer cup  100  will be labeled with the same number indicator. The packer cup  400  includes seal segments  410 ,  420 ,  430  and the base  105 . The seal segments  410 ,  420 ,  430  are interconnected together. The seal segments  410 ,  420 ,  430  are designed to engage and create a seal with the casing (not shown) upon activation of the packer cup  400 . As shown, the seal segments  420 ,  430  have the same thickness, and the seal segment  410  has a different thickness. Additionally, the seal segments  420 ,  430  have the same outer diameter, and seal segment  410  has a smaller outer diameter. Each characteristic (e.g., diameter, length, thickness, number of seal segments) of the seal segment  410 ,  420 ,  430  may be selected based upon the application in the wellbore. 
       FIG. 11  illustrates a view of a packer cup  450 . For convenience, the components in the packer cup  450  that are similar to the components in the packer cup  100  will be labeled with the same number indicator. The packer cup  450  includes seal segments  460 ,  470 ,  480  and the base  105 . The seal segments  460 ,  470 ,  480  are interconnected together. As shown, a first protrusion  465  is formed between seal segments  460 ,  470 , and a second protrusion  475  is formed between seal segments  470 ,  480 . The protrusions  465 ,  470  are formed when the packer cup  450  is being pulled up in the casing, or in the direction of the seal segments  460 ,  470 ,  480 . The protrusions  465 ,  470  are formed as the shoulders of the seal segments  460 ,  470 ,  480  move toward each other due to the movement within the casing, and the seal segments  460 ,  470 ,  480  may contact each other. The protrusions  465 ,  470  provide additional stability to the seal segments  460 ,  470 ,  480  as the packer cup  450  is moved relative to the casing. The seal segments  460 ,  470 ,  480  are designed to engage and create a seal with the casing (not shown) upon activation of the packer cup  450 . As shown, the seal segments  420 ,  430  have the same thickness, and the seal segment  410  has a different thickness. Each characteristic (e.g., diameter, length, thickness, number of seal segments) of the seal segment  460 ,  470 ,  480  may be selected based upon the application in the wellbore. 
       FIG. 12  illustrates a view of a packer cup  500  in an eccentric wellbore  80 . The packer cup  500  includes a seal segment  510  attached to the base  105 . Although the packer cup  500  in  FIG. 12  shows one seal segment  510 , the packer cup  500  includes at least two seal segments. Similar to the seal segments described herein, the seal segment  510  is configured to move from a first shape to a second expanded shape to create a seal with the eccentric wellbore  80 . The seal segment  510  in  FIG. 12  is shown in the second expanded shape. The portions of the seal segment  510  expand in different amounts along an inner circumference of the eccentric wellbore  80 . For instance, a first portion  515  of the seal segment  510  expanded a larger amount than a second portion  520 , and a third portion  530  expanded further than a fourth portion  525 , in order to engage the eccentric wellbore  80 . In this manner, the seal segment  510  of the packer cup  500  is configured to conform to the inner circumference of the eccentric wellbore  80  in the second expanded shape. 
       FIG. 13  illustrates a view of a packer cup  550  in an eccentric wellbore  90 . The packer cup  550  includes a seal segment  560  attached to the base  105 . The packer cup  550  includes at least two seal segments. Similar to the seal segments described herein, the seal segment  560  is configured to move from a first shape to a second expanded shape to create a seal with the eccentric wellbore  90 . The seal segment  560  in  FIG. 13  is shown in the second expanded shape. In order to engage the eccentric wellbore  90 , a first portion  565  of the seal segment  560  has expanded further than a second portion  570 . In this manner, the seal segment  560  of the packer cup  550  is configured to conform to the inner circumference of the eccentric wellbore  90  in the second expanded shape. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Technology Category: 0