SETTING MECHANICAL BARRIERS IN A SINGLE RUN
An operation may require isolation of a wellbore using multiple barriers. A single-run multiple barrier system may be deployed in a wellbore to position a first barrier at a first depth and a second barrier at second depth above the first barrier in the wellbore during a single run of a wellbore tubular string. The first barrier is coupled to a first miming tool. A wellbore tubular string segment couples the first miming tool is coupled to the second barrier. The second barrier is coupled to a second running tool that couples to the wellbore tubular string. The second barrier is locked until the first barrier is independently set at the first depth to prevent the second barrier from being set until the second depth is reached. Setting both barriers in a single run increases efficiency in an operation including reducing costs and time for completion of the operation.
The present invention relates to setting barriers, and more particularly, to setting multiple barriers at two or more different depths in a single run in a wellbore.
BACKGROUNDA wide variety of downhole tools, such as service tools, may be used within a wellbore in connection with the production of hydrocarbons and reworking or servicing a well. In many circumstances an operation may require that multiple barriers be introduced into a borehole or wellbore and set at different depths within the wellbore to isolate portions of the wellbore or the formation. Many operators and government regulations require that a minimum of two barriers be installed in a wellbore. For example, several types of operations for a job, including plug and abandonment and blow-out prevention for a hydrocarbon production, exploration and recovery site, may be implemented that require that multiple barriers be installed in the wellbore. Typically, each barrier must be separately run on a tool string, such as drill pipe or tubing string, into the wellbore and may require a different tool to unlock and set the barrier. As an example, a first barrier may be run into the wellbore with a tool string to a setting depth, set and the tool string is tripped out of the wellbore. The second barrier is connected to the tool string, run in the wellbore and set at a different setting depth and the tool string tripped back out of the well. Each installation of the barriers requires at least two trips down the wellbore which increases wear and tear on equipment and increases risk of mechanical failure both of which contribute to an increase in overall job completion time and costs for the overall job as well as increasing risks to the safety of nearby personnel.
In the drawings and description that follow, like parts are typically marked with the same reference numerals. Specific embodiments are described and are shown in the drawings with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed throughout may be employed separately or in any suitable combination to produce desire results.
For certain downhole operations, barriers or isolation devices are required to be run in the wellbore to isolate portions of the wellbore or the formation. For example, blow-out prevention (BOP) or abandonment of a well may require that multiple barriers are run in the wellbore to isolate portions of the wellbore or the formation. Generally, for barriers deployed on a downhole tool, once one barrier is set, all barriers attached to tubing string or wellbore tubular string are set. An operation that requires setting multiple barriers at different depths requires multiple runs in the wellbore. For example, a downhole tool comprising a barrier is ran in the wellbore to a specified depth and when the depth is reached the barrier is set. The downhole tool is retrieved and another barrier is ran in the wellbore on the same or different downhole tool. Again, once the specified depth is reach the barrier is set and the downhole tool is retrieved. As multiple runs are required for the setting of multiple barriers, the placement of multiple barriers at different depths requires significant time which increases the overall costs of an operation as well as increases the risk to nearby personnel due to multiple instances of contact with the equipment.
The present invention provides increased efficiency for a downhole operation that requires that multiple barriers or isolation devices be set in a wellbore to isolate portions of the wellbore or the formation. Providing a single-run multiple barrier system with multiple barriers that may be set in a wellbore using a single-run of a downhole tool alleviates the need for multiple runs. Setting multiple barriers in a single-run decreases wear and tear on equipment, reduces time for completion of the operation and increases safety by minimizing contact by nearby personnel to the required equipment. For example, a deep set barrier may be connected to a retrieval tool which is connected to a shallow set barrier that is also connected to a retrieval tool of a downhole tool. Both the deep set barrier and the shallow set barrier may be deployed downhole in a single run as the shallow set barrier is locked out until after the deep set barrier has been set.
The rig 106 may comprise a derrick 108 and a rig floor 110 through with a wellbore tubular string extends downward from the drilling rig 106 into the wellbore 114. The rig 106 may comprise a motor 116 that drives a mechanism 118. Mechanism 118 may comprise a winch, a drum, a crank or any other device suitable for deploying and retrieving wellbore tubular string 120 in and out of wellbore 114. In one or more embodiments, the wellbore 114 may comprise a casing 128 or any other liner that extends the length of the wellbore 114 to form an annulus 126.
Wellbore tubular string 120 may comprise one or more sections including, but not limited to, one or more portions such as wellbore tubular string segment 120A and wellbore tubular string segment 120B. Wellbore tubular string 120 may comprise a drill pipe, tool string, tubing string, work string, tubing, drill string or any other piping that is coupled together to deploy one or more downhole tools within the wellbore 114, for example, single-run multiple barrier system 150. In one or more embodiments, the single-run multiple barrier system 150 is deployed in an annulus 126. Wellbore tubular string segment 120A may couple to a single-run multiple barrier system 150. Wellbore tubular string 120 may comprise any number of portions, segments or lengths coupled together to form wellbore tubular string 120. Any number of downhole tools may be coupled to wellbore tubular string 120. Wellbore tubular string 120 deploys the single-run multiple barrier system 150 to the required depth in the wellbore 114. For example, wellbore tubular string segment 120A may couple to one or more other segments of wellbore tubular string 120 and wellbore tubular string segment 120B may couple to one or more other segments of wellbore tubular string 120. Any one or more segments of wellbore tubular string 120 may be threaded or coupled to any one or more other segments of wellbore tubular string 120, one or more single-run multiple barrier systems 150, one or more other downhole tools or any combination thereof.
In one or more embodiments, single-run multiple barrier system 150 may comprise a deep set barrier system 112B at a distal end of the wellbore tubular string 120 and a shallow set barrier system 112A above the deep set barrier system 112B (collectively referred to as barrier systems 112), wellbore tubular string segment 120A and wellbore tubular string segment 120B. In one or more embodiments, single-run multiple barrier system 150 may comprise any number of barrier systems 112. While a single wellbore tubular string segment 120A and a single wellbore tubular string segment 120B are illustrated in
While the operating environment depicted in
With respect to
Locking assembly 610 is illustrated at a distal end of the shallow set barrier system 112A. Shallow set barrier system 112A may include, or be attached to or otherwise coupled to, an inner, actuating mandrel 614, which may be connected or coupled to the wellbore tubular string 120. Locking assembly 610 may include the actuating mandrel 614, attached at a lower end to bottom adapter 616. Actuating mandrel 614 and at least a portion of bottom adapter 616 may be situated within a fluid chamber case 618, a lock 620 or both. The fluid chamber case 618 and the lock 620 may be removably attached, fixedly attached, or even integrally formed with one another. Alternatively, fluid chamber case 618 and lock 620 may be separate.
At least one fluid chamber 622 may be situated between actuating mandrel 614 and lock 620. Fluid chamber 622 may be sealed via one or more seals 624, along with a rupture disk 626, such as rupture disk 412 of
Referring now to
In the run-in-hole, locked position, the lock 620 is in an upward position, in which lugs 634 are engaged with locking portion 642 of the lock 620. As the tool string is lowered into well bore, the locking assembly 610 will remain in the locked position shown in
Once pressure is applied and the locking assembly 610 is unlocked (as shown in
For retrieval, the tool string or wellbore tubular string 120 is simply pulled upwardly out of the wellbore 114. This will cause the lug 634 to re-engage the slot 638. Additionally, as the pressure outside the shallow set barrier system 112A, and thus, the pressure within the fluid chamber 622 is reduced, the lock 620 may move back into the locked position, preventing any subsequent relative movement of the lug rotator ring 636 with respect to the sleeve 640.
While the application of pressure is disclosed above as one triggering event to allow the lug 634 to move within the slot 638, other events may also occur to allow the lug 634 to move within the slot 638. In this case, the lock 620 may be configured to allow the lug 634 to move within the slot after the triggering event has occurred, so long as a predetermined condition is maintained. For example, but not by way of limitation, the triggering event may be a timer reaching a predetermined value, and the predetermined condition may be that the timer has not yet reached a second predetermined value.
Further, the internal lugs 945 and the external lugs 935 are adapted to engage as to support weight below the releasable connection. The size and number of engaging lugs 945, 935, and more specifically, the total cross-sectional area of engagement of the lugs 945, 935, determines the quantity of weight that can be supported by the deep set barrier system 112B, including, but not limited to, the running tool 122B. In one embodiment, four (4) sets 948, 938 of ten (10) lugs 945, 935 are provided on the overshot 940 and the mandrel 930 respectively; the sets 948, 938 are spaced apart at 90-degree intervals circumferentially; the lugs 945, 935 are each approximately ½-inch wide and ¼-inch high; and the deep set barrier system 112B is adapted to support several hundred tons of weight, for example, 500 tons of weight. Assuming the same size of engaging lugs 945, 935, the amount of weight that can be supported by the deep set barrier system 112B changes linearly with the quantity of lugs 945, 935 provided. For example, if the embodiment described above included only half as many lugs 945, 935, the deep set barrier system 112B would be adapted to support 250 tons of weight, and if the embodiment described above included twice as many lugs 945, 935, the deep set barrier system 112B would be adapted to support 1,000 tons of weight. Similarly, assuming the same quantity of engaging lugs 945, 935, the amount of weight that can be supported by the device 100 changes linearly with the size of the lugs 945, 935 provided. For example, if the embodiment described above included the same quantity of lugs 945, 935 but the lugs 945, 935 were only half the size, the device 100 would be adapted to support 250 tons of weight, and if the embodiment described above included the same quantity of lugs 945, 935 but the lugs 945, 935 were twice the size, the deep set barrier system 112B would be adapted to support 1,000 tons of weight.
As best depicted in
Referring again to
To disengage the internal lugs 945 from the external lugs 935, a 45-degree rotation opposite of the first direction is applied to the wellbore tubular string 120 from the surface of the wellbore 114, thereby rotating the overshot 940 with respect to the mandrel 930. To ensure that the overshot 940 is not over-rotated with respect to the mandrel 930 during release, the mandrel 930 may comprise a rotational stop 934 that extends between at least two of the external lugs 935 to act as a barrier for preventing the internal lugs 945 from reconnecting and reengaging with the external lugs 935.
In another embodiment, the slide lock 950 may be biased to respond to differential pressure created by applying pressure to the flow bore 990 rather than applying pressure to the annulus 126. Again, because the spring chamber 975 is in fluid communication with the flow bore 990 via ports 965 in the spring mandrel 960, by pressuring up the fluid within the flow bore 990, a differential pressure is created across the slide lock 950, thereby allowing the slide lock 950 to overcome the bias of the spring 970 and move downwardly to the unlocked position shown in
Once the deep set barrier system 112B is unlocked, and with the lower surface 946 of the internal lugs 945 shouldered against the upper surface 996 of the external lugs 935, an opposite rotation may be applied to the wellbore tubular string 120, thereby causing the top adapter 910 and overshot 940 to rotate opposite of the first direction with respect to the mandrel 930. The rotation will be less than 360 degrees, and in the embodiments depicted herein where four (4) interacting sets of lugs 938, 948 are positioned 90 degrees apart circumferentially, the rotation will be 45 degrees. As shown in
Once the overshot 940 is released from the mandrel 930, the top adapter 910 and the overshot 940 are removable from the remaining components of the deep set barrier system 112B as shown in
Further, in an embodiment, the alignment key 949 has a longitudinal length that exceeds the distance between two of the lugs 935 on the mandrel 930. Therefore, because the angled alignment key 949 will not fit between two lugs 935 on the mandrel 930, the overshot 940 and mandrel 390 cannot form a partial connection. Instead, the overshot 940 must be lowered completely over the mandrel 930 so that when the overshot 940 is rotated to form the releasable connection, the sets 948 of lugs 945 on the overshot 940 and the sets 938 of lugs 935 on the mandrel 930 are fully engaged, and the angled alignment key 949 is positioned below the lowermost mandrel lug 935.
Referring now to
As the overshot 940 continues moving downwardly in a longitudinal direction, the guide key 947 traverses the J-slot 937, and the angled shape of the J-slot 937 will thereby impart a maximum 990-degree rotation in the first direction to the overshot 940. As shown in
The running tool 122B is now reconnected and locked so that the isolation device 124B can be retrieved from the wellbore 114. When the deep set barrier system 112B is in the configuration shown in
Thus, deep set barrier system 112B comprises a releasable, weight-supporting connection via interacting and engaging lugs 935, 945 that can be designed to support large quantities of weight, such as 500 tons, for example. Further, the deep set barrier system 112B facilitates easy release from an isolation device 124B, such as when operating from a floating offshore rig, because the lugs 935, 945 are disconnected via a 45-degree opposite rotation of the overshot 940 with respect to the mandrel 930. When reconnecting the lugs 935, 945, a 45-degree rotation in the first direction may be imparted automatically via a guide key 947 interacting with a J-slot 937. The deep set barrier system 112B may further comprise several safety features, such as a slide lock 950 that requires multiple actions to open in the run-in position, thereby preventing inadvertent disconnection, an alignment key 949 having a length that prevents a partial connection between the lugs 945 of the overshot 940 and the lugs 935 of the mandrel 930, and a rotational stop 934 that prevents inadvertent re-connection during release of the overshot 940 from the mandrel 930.
At step 1106, it is determined if the setting depth for the deep set barrier system 112B has been reached. The setting depth may be based on one or more parameters of the formation 102, the wellbore 114 or any other parameter or combination thereof. The depth of each component of the single-run multiple barrier system 150 as it is deployed into the wellbore 114 may be determined by any one or more techniques for determining depth in a wellbore 114. For example, the length of each segment of wellbore tubular string 120 and any downhole tool attached to the wellbore tubular string may be known such that as the wellbore tubular string 120 is ran in the wellbore 114, the depth of the distal end of or any portion along the wellbore tubular string 120 is known
At step 1112, once the setting depth for the deep set barrier system 112B has been reached, deployment of the wellbore tubular string 120 is stopped or halted and the isolation device 124B (for example, the deep set barrier) is set. For example, actuation of motor 116 and winch 118 of
At step 1118, the deep set barrier system 112B is disconnected from the wellbore tubular string segment 120B. For example, running tool 122B may be disconnected from wellbore tubular string segment 120B as discussed below with respect to
At step 1124, once the deep set barrier system 112B has been disconnected from the wellbore tubular string 120, the wellbore tubular string 120 is retracted or picked up to dispose or position the shallow set barrier system 112A at a specified, determined, required or selected depth, a shallow set depth. For example, motor 116 and winch 118 of
At step 1130, it is determined if the setting depth for the shallow set barrier system has been reached. The setting depth may be based on one or more parameters of the formation 102, the wellbore 114 or any other parameter or combination thereof. The depth of each component of the single-run multiple barrier system 150 as it is retracted, retrieved, picked up or pulled from the wellbore 114 may be determined by any one or more techniques for determining depth in a wellbore as discussed above with respect to step 1106.
At step 1136, once the setting depth for the shallow set barrier system 112B has been reached, deployment of the wellbore tubular string 120 is halted or stopped and the isolation device 124A (for example, the shallow set barrier) is set. For example, actuation of motor 116 and winch 118 of
At step 1142, once the isolation device 124A has been set, the running tool 122A is disconnected from the wellbore tubular string segment 120A. For example, the running tool 122A may be disconnected from the wellbore tubular string segment 120A hydraulically, mechanically, or both. In one or more embodiments, the shallow set barrier system 112A including the running tool 122A is disconnected from the wellbore tubular string segment 120A in a similar manner as discussed above with respect to the deep set barrier system 112B.
At step 1148, any remaining segments of the wellbore tubular string 120 are retracted, retrieved or tripped out of the wellbore 114. One or more other steps may be initiated once the wellbore tubular string 120 has been tripped out of the wellbore 114 to complete a given operation.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.
In one or more embodiments, a method of setting a single-run multiple barrier system comprises deploying a single-run multiple barrier system on a wellbore tubular string in a wellbore of a formation, wherein the single-run multiple barrier system comprises a deep set barrier system at a distal end of the wellbore tubular string and a shallow set barrier above the deep set barrier system, determining if a first depth in the wellbore has been reached by the single-run multiple barrier system, setting a first isolation device of the deep set barrier system, wherein the shallow set barrier system comprises a rupture disk that prevents a lug from moving within a continuous j-slot to prevent setting of the shallow set barrier system during setting of the first isolation device, disconnecting the deep set barrier system from the wellbore tubular string, retrieving the wellbore tubular string to a second depth, setting a second isolation device of the shallow set barrier system, disconnecting the shallow set barrier system from the wellbore tubular string. In one or more embodiments, setting the second device comprises rupturing the rupture disk, allowing the lug to move within the continuous j-slot and lifting upward and pushing downward on the wellbore tubular string. In one or more embodiments, the first isolation device is coupled to a first running tool, and wherein disconnecting the deep set barrier system from the wellbore tubular string comprises disengaging the first running tool from the wellbore tubular string. In one or more embodiments, the shallow set barrier system is coupled to a second running tool, wherein the second running tool is coupled to the wellbore tubular string, and wherein disconnecting the shallow set barrier system from the wellbore tubular string comprises disengaging the second running tool from the wellbore tubular string. In one or more embodiments, the method further comprises extending one or more first projections of one or more first anchors of the deep set barrier system to contact at least one of the wellbore, an annulus disposed within the wellbore, and a casing disposed within the wellbore. In one or more embodiments, the method further comprises extending one or more second projections of one or more second anchors of the shallow set barrier system to contact at least one of the wellbore, an annulus disposed within the wellbore, and a casing disposed within the wellbore. In one or more embodiments, the method further comprises maintaining positioning of the first isolation device in an annulus of the wellbore via a first centralizer. In one or more embodiments, the method further comprises maintaining positioning of the second isolation device in an annulus of the wellbore via a second centralizer. In one or more embodiments, at least one of the first setting depth and the second setting depth is based on one or more parameters of the formation. In one or more embodiments, the method further comprises retrieving the wellbore tubular string from the wellbore.
In one or more embodiments, a single-run multiple barrier system comprises a deep set barrier system, wherein the deep set barrier system comprises a first isolation device and a first running tool, wherein the first running tool couples to a first portion of a wellbore tubular string, a shallow set barrier system, wherein the shallow set barrier system comprises a second isolation device and second running tool, wherein the second running tool couples to a second portion of a wellbore tubular string, and a locking assembly of the shallow set barrier system, wherein the locking assembly is locked and unlocked independent of the deep set barrier system. In one or more embodiments, the locking assembly comprises a rupture disk that prevents a lug from moving within a continuous j-slot to prevent setting of the shallow set barrier system during setting of the first isolation device. In one or more embodiments, the lug moves within the continuous j-slot when the rupture disk ruptures to set the second isolation device. In one or more embodiments, the deep set barrier system further comprises a first running tool coupled to the first isolation device and the wellbore tubular string and wherein the first running tool disconnects from the wellbore tubular string to set the first isolation device and reconnects with the wellbore tubular string to retrieve the first isolation device. hi one or more embodiments, the shallow set barrier system further comprises a second running tool coupled to the second isolation device and the wellbore tubular string and wherein the second running tool disconnects from the wellbore tubular string to set the second isolation device and reconnects with the wellbore tubular string to retrieve the second isolation device. In one or more embodiments, the deep set barrier system further comprises one or more first anchors and one or more first projections of the one or more first anchors, wherein the one or more first projections extend to contact at least one of the wellbore, an annulus disposed within the wellbore and a casing disposed within the wellbore. In one or more embodiments, the shallow set barrier system further comprises one or more second anchors and one or more second projections of the one or more second anchors, wherein the one or more second projections extend to contact at least one of the wellbore, an annulus disposed within the wellbore and a casing disposed within the wellbore. In one or more embodiments, the deep set barrier system further comprises a first centralizer. In one or more embodiments, the shallow set barrier system further comprises a second centralizer. In one or more embodiments the wellbore tubular string comprises a first wellbore tubular string segment coupled to the first running tool and the shallow set barrier system and a second wellbore tubular string segment coupled to the second running tool, wherein the first running tool disengages from the first wellbore tubular string segment to set the deep set barrier system, and wherein the second running tool disengages from the second wellbore tubular string segment to set the shallow set barrier system.
Claims
1. A method of setting a single-run multiple barrier system comprising:
- deploying a single-run multiple barrier system on a wellbore tubular string in a wellbore of a formation, wherein the single-run multiple barrier system comprises a deep set barrier system at a distal end of the wellbore tubular string and a shallow set barrier above the deep set barrier system;
- determining if a first depth in the wellbore has been reached by the single-run multiple barrier system;
- setting a first isolation device of the deep set barrier system, wherein the shallow set barrier system comprises a rupture disk that prevents a lug from moving within a continuous j-slot to prevent setting of the shallow set barrier system during setting of the first isolation device;
- disconnecting the deep set barrier system from the wellbore tubular string;
- retrieving the wellbore tubular string to a second depth;
- setting a second isolation device of the shallow set barrier system; and
- disconnecting the shallow set barrier system from the wellbore tubular string.
2. The method of claim 1, wherein setting the second device comprises:
- rupturing the rupture disk;
- allowing the lug to move within the continuous j-slot; and
- lifting upward and pushing downward on the wellbore tubular string.
3. The method of claim 1, wherein the first isolation device is coupled to a first running tool, and wherein disconnecting the deep set barrier system from the wellbore tubular string comprises disengaging the first running tool from the wellbore tubular string.
4. The method of claim 1, wherein the shallow set barrier system is coupled to a second running tool, wherein the second running tool is coupled to the wellbore tubular string, and wherein disconnecting the shallow set barrier system from the wellbore tubular string comprises disengaging the second running tool from the wellbore tubular string.
5. The method of claim 1, further comprising: extending one or more first projections of one or more first anchors of the deep set barrier system to contact at least one of the wellbore, an annulus disposed within the wellbore, and a casing disposed within the wellbore.
6. The method of claim 1, further comprising: extending one or more second projections of one or more second anchors of the shallow set barrier system to contact at least one of the wellbore, an annulus disposed within the wellbore, and a casing disposed within the wellbore.
7. The method of claim 1, further comprising: maintaining positioning of the first isolation device in an annulus of the wellbore via a first centralizer.
8. The method of claim 1, further comprising: maintaining positioning of the second isolation device in an annulus of the wellbore via a second centralizer.
9. The method of claim 1, wherein at least one of the first setting depth and the second setting depth is based on one or more parameters of the formation.
10. The method of claim 1, further comprising: retrieving the wellbore tubular string from the wellbore.
11. A single-run multiple barrier system comprising:
- a deep set barrier system, wherein the deep set barrier system comprises a first isolation device and a first running tool, wherein the first running tool couples to a first portion of a wellbore tubular string;
- a shallow set barrier system, wherein the shallow set barrier system comprises a second isolation device and second running tool, wherein the second running tool couples to a second portion of a wellbore tubular string; and
- a locking assembly of the shallow set barrier system, wherein the locking assembly is locked and unlocked independent of the deep set barrier system.
12. The single-run multiple barrier system of claim 11, wherein the locking assembly comprises a rupture disk that prevents a lug from moving within a continuous j-slot to prevent setting of the shallow set barrier system during setting of the first isolation device.
13. The single-run multiple barrier system of claim 12, wherein the lug moves within the continuous j-slot when the rupture disk ruptures to set the second isolation device.
14. The single-run multiple barrier system of claim 11, wherein the deep set barrier system further comprises:
- a first running tool coupled to the first isolation device and the wellbore tubular string; and
- wherein the first running tool disconnects from the wellbore tubular string to set the first isolation device and reconnects with the wellbore tubular string to retrieve the first isolation device.
15. The single-run multiple barrier system of claim 11, where the shallow set barrier system further comprises:
- a second running tool coupled to the second isolation device and the wellbore tubular string; and
- wherein the second running tool disconnects from the wellbore tubular string to set the second isolation device and reconnects with the wellbore tubular string to retrieve the second isolation device.
16. The single-run multiple barrier system of claim 11, wherein the deep set barrier system further comprises:
- one or more first anchors; and
- one or more first projections of the one or more first anchors, wherein the one or more first projections extend to contact at least one of the wellbore, an annulus disposed within the wellbore and a casing disposed within the wellbore.
17. The single-run multiple barrier system of claim 11, wherein the shallow set barrier system further comprises:
- one or more second anchors; and
- one or more second projections of the one or more second anchors, wherein the one or more second projections extend to contact at least one of the wellbore, an annulus disposed within the wellbore and a casing disposed within the wellbore.
18. The single-run multiple barrier system of claim 11, wherein the deep set barrier system further comprises a first centralizer.
19. The single-run multiple barrier system of claim 11, wherein the shallow set barrier system further comprises a second centralizer.
20. The single-run multiple barrier system of claim 11, wherein the wellbore tubular string comprises a first wellbore tubular string segment coupled to the first running tool and the shallow set barrier system and a second wellbore tubular string segment coupled to the second running tool, wherein the first running tool disengages from the first wellbore tubular string segment to set the deep set barrier system, and wherein the second running tool disengages from the second wellbore tubular string segment to set the shallow set barrier system.
Type: Application
Filed: Jun 13, 2018
Publication Date: Sep 9, 2021
Inventors: David Allen Dockweiler (Humble, TX), Garry Martin Howitt (Midmar), William Ellis Standridge (Madill, OK)
Application Number: 17/053,895