Patent Application
20250012157
None.
Not applicable.
Not applicable.
Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations that may be located onshore or offshore. The construction of a hydrocarbon producing well can comprise a number of different steps. Typically, the construction begins with drilling a wellbore at a desired wellsite, treating the wellbore to optimize production of hydrocarbons, and installing completion equipment to produce the hydrocarbons from the subterranean formation. During the construction of some wells, the wellbore may be completed in smaller stages or sub-stages. In some scenarios, the wellbore may be stimulated after the installation of a portion of the completion equipment or between sub-stages of completion equipment.
Well construction in tortuous or deep wells can require the installation of seal assemblies on long strings of tubing. The drilling operation may result in a long winding or wandering path that the stings of tubing are installed within. The location of a seal surface, e.g., polish bore, along or at the end of this irregular path can be difficult to determine requiring a long seal bore. Likewise, installing and/or retaining a seal assembly with the seal surface can be problematic. For example, temperature and/or pressure changes within the tubing, e.g., a stimulation operation, can result in the expansion and/or contraction of the tubing resulting in an unplanned disengagement of seals from the seal surface. A method of retaining the seal assembly within the seal bore is desirable.
For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.
It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.
As used herein, orientation terms “uphole,” “downhole,” “up,” and “down” are defined relative to the location of the earth's surface relative to the subterranean formation. “Down” and “downhole” are directed opposite of or away from the earth's surface, towards the subterranean formation. “Up” and “uphole” are directed in the direction of the earth's surface, away from the subterranean formation or a source of well fluid. “Fluidically coupled” means that two or more components have communicating internal passageways through which fluid, if present, can flow. A first component and a second component may be “fluidically coupled” via a third component located between the first component and the second component if the first component has internal passageway(s) that communicates with internal passageway(s) of the third component, and if the same internal passageway(s) of the third component communicates with internal passageway(s) of the second component.
Hydrocarbons, such as oil and gas, are produced or obtained from subterranean reservoir formations that may be located onshore or offshore. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation typically involve a number of construction steps such as drilling a wellbore at a desired well site, isolating the wellbore with a barrier material, completing the wellbore with various production equipment, treating the wellbore to optimize production of hydrocarbons, and providing surface production equipment for the recovery of hydrocarbons from the wellhead.
During the completion operations, a completion string, for example, a packer and at least one sand screen, may be used to isolate a production zone when erosive sand particles are present or predicted within the fluids produced from the formation, e.g., production fluids. The completion operation can comprise and upper completion string and a lower completion string, also referred to as a lower completion assembly. Generally, a lower completion assembly comprises an isolation packer and at least one sand screen comprising a base pipe with a flow passage and a filter media, e.g., sand screen, disposed around a portion of the base pipe. The filter media can be formed with a filter flow area formed between the filter media and the base pipe. The isolation packer can anchor the lower completion and form a seal between the packer and the inner surface of the wellbore. The lower completion can also comprise a seal surface, e.g., a polish bore. A string of tubing comprising a seal assembly can locate and seal within the seal surface.
Wellbore operations can expose the lower completion to varied conditions, e.g., temperatures and pressures, and the seal assemblies must be suitable for either the resultant loads or pipe movement. For example, extended reach completions or multilateral completions can utilize lower completions divided into multiple sections, also referred to as drop-off sections, that include a seal surface, e.g., a polished bore. A completion seal interface, e.g., seal assembly, can be sealingly coupled to the polished bore to isolate another portion of the wellbore from this portion of the lower completion or to produce wellbore fluids to surface. However, given the nature of well construction these seal interfaces must account for a degree of variation in planned location of the polished bore, e.g., measure depth, due to the tortuous path of the wellbore and/or the extreme measured depth of the polished bore, for example, up to two meters travel uphole or downhole. This degree of variation, e.g., two meters of travel, can exclude the use of mechanically anchored seal assemblies, e.g., latch technology. Simulation operations can increase the complexity by adding additional tension and/or compression loading to the seal for loading on the string, for example, a stimulation operation can generate a temperature change of up to 100 C within the tubing. A temperature change experience during simulation operation can generate significant stress levels in a tubing string anchored to a lower completion as the tubing string expands and contracts. In response, an anchor is often removed or disengaged to allow the seal interface to float or move axially with tubing compression or tension, however this “float” exposes the plurality of tubulars and the connections between to tubulars to high piston loads which can result in mechanical failure. A completion interface that can sealingly couple to a polish bore and selectively anchor during simulation operations is desirable.
One solution to the problem of selectively anchoring can utilize a pressure sensitive mechanism. In some embodiments, a method of selectively anchoring tubing interfaces, e.g., conventional seal mandrels, with a pressure activated casing anchor device can activate, e.g., anchor, in response to pressure applied to the tubing string. For example, the tubing interfaces can “float” or stroke within the polish bore but can be locked, e.g., anchored, in place in response to applied pressure.
The method of selectively anchoring tubing interfaces can be beneficial when swellpackers, e.g., packers not anchored to the wellbore, are utilized in sections of drop-off liners and multilateral junction assemblies. In some embodiments, the method of selectively anchoring tubing interfaces comprises pressure activated slips and/or buttons. For example, applied pressure within the tubing string with the tubing interface can result in an upward, e.g., uphole direction, piston load and the selective anchoring mechanism can be activated extending the slips/buttons and anchoring the tubing string, e.g., tubing interface, to the lower completion portion, e.g., the polish bore. Once this pressure is reduced the slips/buttons will retract and the upper string will move back to its original as installed position. In some embodiments, the anchor will not activate during thermal changes, thus the tubing interface can float or stroke within the polish bore as a result of contraction of the tubing through cooling. In some embodiments, the internal pressure can be applied along with subsequent thermal cooling, the pressure activated anchor can activate to retain the tubing interface within the polish bore. By application of this method, interfaces between tubular sections, such as drop-off liner and multilateral completion junctions, can be further ruggedized ultimately increasing stimulation and production enhancement methods leading to greater well length and production life.
Turning now to
A production string 136 may be positioned within the wellbore 102 and extend from the offshore platform 130 into the subterranean formation 110. The production string 136 can be any piping, tubular, or fluid conduit including, but not limited to, drill pipe, production tubing, casing, coiled tubing, and any combination thereof. The production string 136 provides a conduit for production fluids extracted from the formation 110 to travel to the surface. The production string 136 may additionally provide a conduit for fluids to be conveyed downhole and injected into the formation 110, such as in an injection operation.
In some embodiments, the production string 136 can be releasably coupled to a lower completion 140. For example, the production string 136 can sealingly couple to the lower completion 140 by a completion interface (not shown). In some embodiments, the production string 136 can sealingly couple and mechanically couple to the lower completion 140 by a selective anchor as will be described further herein. The lower completion 140 can divide the production zone into various production intervals adjacent the formation 110. The production zone can be the area within the wellbore 102 where various wellbore operations are to be undertaken using the lower completion 140, such as production or injection operations.
As illustrated in
In some embodiments, a tubing string with a completion interface can extend from the rig 130 to the lower completion 140. In a first scenario, the tubing string can be the production string 136 configured to sealingly couple to the polish bore 148 of the lower completion 140. The production string 136 can fluidically couple the formation 110 to a surface production facility (not shown) via the lower completion 140. In a second scenario, the tubing string can be a service string, e.g., drill pipe or heavy weight tubing, configured to sealingly couple to the polish bore 148. For example, the tubing string can be conveyed into the wellbore 102 to sealingly engage the polish bore 148 for testing of the annulus between the tubing string and wellbore 102 or simulation of the wellbore 102. In both scenarios, the tubing string 136 may be conveyed from the rig floor of the rig 130 to the lower completion 140 located at the distal end of the wellbore 102.
The measured depth, e.g., total distance, from the rig floor to the lower completion 140 can be in a range of 30,000 feet to 40,000 feet. The measured depth can include “A” lateral distance along the generally horizontal portion 108, “B” a target depth measured along the generally vertical portion 106, and “C” a water depth measured from the rig floor to the surface location 104 of the sea-bed. For example, horizontal wells in the United States averaged 10,000 ft in early 2000s and 18,000 by 2019 in lateral length, e.g., “A” lateral distance, according to the US Energy Information Administration. The target depth, e.g., “B” target depth, is generally the average depth of the subterranean formation 110 from the surface 104. For example, the US average depth of exploratory and development wells on US land was 5,500 feet during the 2000s. The water depth “C” can depend on the type of offshore platform 130 utilized. For example, “C” water depth can be 200 feet to 1,700 feet for a fixed platform, 200 feet to 20,000 feet for a semi-submersible platform, or up to 12,100 feet for a drillship.
Turning now to
The lower completion 140, as shown in
Turning now to
Turning now to
The button slip 250 can be generally rod shaped with an anchoring feature. Turning now to
In some embodiments, the fluid port 246 can include a filter insert 356. The filter insert 356 can be a generally disk shape with a filter pattern 358 configured to exclude particulates and/or fines from entering the fluid port 246. The filter insert 356 can sealingly couple to a port shoulder 360 within the fluid port 246 of the sub body 240. The filter insert 356 can be retained on the port shoulder 360 by a retaining ring 362, a threaded ring, a snap ring, or any other suitable retaining device. The filter pattern 358 can be a plurality of holes, a woven mesh, a woven cloth, a series of welded ribs, or combinations thereof.
During operation, pressure within the anchor sub 210 can extend the plurality of button slip 250 to grip the casing string 112. Applied pressure to the interior of the anchor sub 210 can generate a pressure differential between the interior pressure and the wellbore environment, e.g., formation pressure 110. The wellbore environment within an annular space between the tubing string 136 and the wellbore 102 and/or casing string 112 can include formation pressure 110, applied pressure from surface 104, applied pressure from rig floor of the offshore platform 130, or combinations thereof. Differential pressure from within the sub body 240 can extend the button slips 250 by the piston area of the port 248 via the seals 340. The differential pressure can generate an upward force via the piston area to compress the retaining spring 316 and extend the button slip 250. The applied pressure value to extend the slips 250 can be determined by the number of springs 316 and the spring stress level of the springs 316. In some embodiments, a secondary retaining spring 318 can be utilized to increase the predetermined applied pressure value required to extend the plurality of button slips 250. The button slip 250 can anchor or grip the inner surface of the casing string and/or a shroud with the top surface 334 and/or the anchoring feature 338.
The completion operation may comprise additional completion assemblies with pressure activated mechanisms, e.g., completion packers or liner hangers. A pressure lockout device can prevent the anchor from activating until a predetermined pressure is exceeded. Turning now to
During operation, the lockout mechanism 400 can retain the button slip 412 in a first position. The lockout mechanism 400 can retain the button slip 412 in the first position as pressure is applied to the interior of the anchor sub, e.g., anchor sub 210, to actuate other completion assemblies. The lockout mechanism 400 can be disabled or released by applied pressure within the anchor sub exceeding a predetermined value. Applied pressure can create a differential pressure between the interior pressure and the wellbore environment to generate an upward force via the piston area, e.g., the anchor port 430. The upward force can shear the shear ring 410 into an inner portion 432 and an outer portion 434. The upward force from the pressure differential can compress the retaining spring 316, or nested retaining springs 316, 318, and extend the button slip 412. The button slip 412 can anchor or grip the inner surface of the casing string and/or a shroud with the top surface and/or the anchoring feature 428.
Turning now to
With reference to
With reference to
With reference to
With reference to
Turning to
In some embodiments, the lateral wellbore 616 can include a lateral completion 636 comprising a plurality of zonal packers 626 and a plurality of sand screens 628. In some embodiments, the sand screens 628 can include flow valves 630. A polish bore 638 and a shroud 640 can be coupled to the uphole end 642 of the lateral completion 636.
The selective anchor assembly can facilitate the installation of a branch completion. In some embodiments, a branch completion 650 comprises a liner hanger 652, a branch junction 654, a main junction seal 658, and the selective anchor 200.
In some embodiments, a completion operation can convey the branch completion 650 into the main wellbore 610 via a service tool and workstring. The completion deflector 634 can guide or direct the selective anchor 200 into the lateral wellbore 616. The completion operation can convey the branch completion 650 to sealingly couple the selective anchor 200 to the lateral completion 636 while simultaneously, or in a sequence of steps, coupling the main junction seal 658 to the completion deflector 634. The seal assembly 214 of the selective anchor 200 can be located in a first position 500 within the polish bore 638 of the lateral completion 636 as shown in
The completion operation can set or activate the liner hanger 652 with the service tool, e.g., a liner hanger setting tool, to sealingly engage and anchor to a primary casing string 660 within the primary wellbore 662. The completion operation can apply pressure, tension, compression, or combinations thereof during the setting of the liner hanger 652 with the liner hanger setting tool (not shown). The internal pressure applied to the branch completion 650 during the setting process can activate the selective anchor 200. As previously described and illustrated in
Turning to
In some embodiments, a modular completion 736 can be coupled to the lower completion 720 and coupled to a main casing string 712 within the main wellbore 702. The modular completion 736 comprises a liner hanger 740, a plurality of zonal packers 730, a plurality of sand screens 732, or combinations thereof and the selective anchor 200.
In some embodiments, a completion operation can convey the modular completion 736 into the main wellbore 702 via a service tool, e.g., a liner hanger setting tool, and a workstring. The completion operation can sealingly engage the polish bore 726 with the seal assembly 214 on the selective anchor 200 and, via a completion schedule comprising a number of consecutive steps, establish a first position 500 with the effective seal length “R” located in the middle of the polish bore 726.
The completion operation can set or activate the liner hanger 740 with the service tool, e.g., a liner hanger setting tool, to sealingly engage and anchor to a main casing string 712 within the main wellbore 702. The completion operation can apply pressure, tension, compression, or combinations thereof during the setting of the liner hanger 740 with the liner hanger setting tool (not shown). The internal pressure applied to the modular completion 736 during the setting process can activate the selective anchor 200. As previously described and illustrated in
The selective anchor can be utilized in a wellbore servicing operation to isolate a completion. Turning to
In some embodiments, an upper completion 810 can be coupled to the lower completion 820 by a seal assembly 830. The upper completion 810 comprises a production packer 832, an extension 834, and the seal assembly 830. Although the upper completion 810 is described as comprising a production packer 832, an extension 834, and a seal assembly 830, it is understood that the upper completion 810 can include a number of different devices with a variety of uses, for example, a sand screen, a production valve, an inflow control device, a flow control device, a plurality of sensors, a communication mechanism, a unit controller, a power source, a second packer, a third packer, or combinations thereof. In some embodiments, the tubing string 136 can be mechanically coupled to the production packer 832 or releasably coupled to the packer.
In some embodiments, a wellbore servicing operation can release and retrieve the upper completion 810. For example, the wellbore servicing operation can utilize one or more methods to convey the tubing string 136, the production packer 832, and the seal assembly 830 back to surface, e.g., platform 130.
Turning now to
The wellbore servicing operation can perform the wellbore servicing operation, e.g., perforating the casing or pumping a treatment, with the service tool assembly 840. The wellbore servicing operation can apply pressure, tension, compression, or combinations thereof during the servicing operation. The internal pressure applied to the service tool assembly 840 can activate the selective anchor 200. As previously described and illustrated in
The following are non-limiting, specific embodiments in accordance and with the present disclosure:
A first embodiment, which is a selective anchor assembly for a downhole completion, comprising an anchor sub generally cylindrical in shape with an outer surface and an inner passage; at least one button slip sealingly coupled to a corresponding piston port on the anchor sub, wherein the corresponding piston port is fluidically coupled to the inner passage; a seal assembly coupled to the anchor sub comprising at least one seal unit; wherein the selective anchor is configured to slidingly and sealingly engage a polish bore; and wherein the selective anchor is configured to anchor to a shroud coupled to the polish bore in response to pressure applied to the inner passage of the anchor sub.
A second embodiment, which is the selective anchor assembly of the first embodiment, wherein the at least one button slip is configured in a run-in position by at least one retention spring.
A third embodiment, which is the selective anchor assembly of any of the first and the second embodiments, wherein the at least one button slip is configured to move to an anchoring position in response to an applied pressure within the inner passage of the anchor sub.
A fourth embodiment, which is the selective anchor assembly of any of the first through the third embodiments, wherein an outer surface of the button slip travels past the outer surface of the anchor sub in the anchoring position, and wherein the outer surface of the button slip grips an inner surface of the shroud in the anchoring position; and wherein the shroud is i) a generally tubular shape configured to guide the seal assembly into the polish bore, ii) a portion of the casing string, or ii) the casing string.
A fifth embodiment, which is the selective anchor assembly of the first through the fourth embodiments, wherein the seal unit comprises a seal mandrel and a service seal.
A sixth embodiment, which is the selective anchor assembly of any of the first through the fifth embodiments, wherein the seal mandrel is generally cylindrical in shape with an outer surface, an inner passage, and a seal surface; and wherein the service seal is i) an elastomeric seal, ii) a thermoplastic seal, or combinations thereof, and sealingly engaged with the seal surface of the seal mandrel.
A seventh embodiment, which is the selective anchor assembly of any of the first through the sixth embodiment, further comprising a filter insert with a filter pattern coupled to a fluid port; wherein the filter pattern is configured to exclude particulates from a wellbore fluid within the inner passage; and wherein the fluid port fluidically couples the inner passage to the corresponding piston port.
A eighth embodiment, which is the selective anchor assembly of any of the first through the seventh embodiments, wherein the wellbore fluids are i) injection fluids or ii) production fluids.
A ninth embodiment, which is the selective anchor assembly of any of the first through the eighth embodiments, wherein the applied pressure within the inner passage of the anchor sub is in response to i) a completion operation, ii) a service operation, or iii) an injection operation.
A tenth embodiment, which is a method of selectively anchoring a selective anchor assembly to a downhole completion, comprising conveying, by a tubing string, the selective anchor assembly into a wellbore of a remote wellsite; positioning a seal assembly of the selective anchor assembly in a first position within a seal surface coupled to the downhole completion, and wherein a plurality of button slips of an anchor sub are in a first position; and positioning the selective anchor assembly into a fourth position in response to a wellbore servicing operation, and wherein the plurality of button slips of the anchor sub are in a second position.
An eleventh embodiment, which is the method of the tenth embodiments, further comprising positioning, by a first temperature change, the seal assembly of the selective anchor assembly in a second position within the seal surface coupled to the downhole completion; and wherein the first temperature change is an increase in temperature of the tubing string.
A twelfth embodiment, which is the method of any of the tenth through the eleventh embodiments, wherein the plurality of button slips of the anchor sub are in the first position.
A thirteenth embodiment, which is the method of any of the tenth through the twelfth embodiments, further comprising positioning, by a second temperature change, the seal assembly of the selective anchor assembly in a third position within the seal surface coupled to the downhole completion; and wherein the second temperature change is a decrease in temperature of the tubing string.
A fourteenth embodiment, which is the method of the tenth through the thirteenth embodiment, wherein the plurality of button slips of the anchor sub are in the first position.
A fifteenth embodiment, which is the method of any of the tenth through the fourteenth embodiment, wherein the downhole completion is a lateral completion within a multilateral well.
A sixteenth embodiment, which is the method of any of the tenth through the fifteenth embodiment, wherein the downhole completion is a modular completion with an Extended Reach Drilling (ERD) well.
A seventeenth embodiment, which is the method of any of the tenth through the sixteenth embodiment, wherein the downhole completion is a lower completion within a horizontal wellbore.
A eighteenth embodiment, which is the method of any of the tenth through the seventeenth embodiment, wherein the wellbore servicing operation comprises a pumping operation; and wherein the pumping operation increases a pressure value within an inner passage of the selective anchor assembly.
A nineteenth embodiment, which is a wellbore fluid isolation tool system for a downhole completion, comprising an anchor sub generally cylindrical in shape with an outer surface and an inner passage coupled to a tubing string; at least one button slip sealingly coupled to a corresponding piston port on the anchor sub, wherein the corresponding piston port is fluidically coupled to the inner passage by a fluid port; a seal assembly coupled to the anchor sub comprising at least one seal unit, wherein the seal assembly comprises at least one seal mandrel and at least one service seal; a polish bore coupled to the downhole completion, wherein the polish bore is configured to sealingly engage the seal assembly; and wherein the wellbore fluid isolation system is configured to: establishing, by a completion operation, a first position with the seal assembly sealingly engaging the polish bore coupled to the downhole completion, wherein an annulus is formed between an outer surface of the tubing string and an inner surface of a casing string, and wherein wellbore fluids within the inner passage of the seal assembly are isolated from the annulus; and anchoring the wellbore fluid isolation system in a fourth position by activating the at least one button slip to grip the inner surface of the casing string.
A twentieth embodiment, which is the wellbore fluid isolation tool system of the nineteenth embodiment, wherein the wellbore fluid isolation system is further configured to: conveying, by a first temperature change, the seal assembly to a second position via a downhole force, wherein the first temperature change is an increase in a temperature of the tubing string, and wherein the downhole force is in response to an elongation of the tubing string in response to the first temperature change.
A twenty-first embodiment, which is the wellbore fluid isolation tool system of the nineteenth and twentieth embodiment, wherein the wellbore fluid isolation system is further configured to: conveying, by a second temperature change, the seal assembly to a third position via an uphole force, wherein the second temperature change is a decrease in a temperature of the tubing string, and wherein the uphole force is in response to a contraction of the tubing string in response to the second temperature change.
While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=RI+k*(Ru−RI), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.
