Resettable packer system for pumping operations
By using a resettable packer system in the well, the sliding inner sleeve, fixed outer sleeve and expandable packer are used to solve the complex problems of packer seating and unsealing in the prior art, and a fast and efficient pumping operation is achieved.
Patent Information
- Application Number
- CN202380062236.5
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Priority Date
- 2022-08-26
- Filing Date
- 2023-08-25
- Publication Date
- 2025-05-06
AI Technical Summary
In the in-well pumping operation, the sealing and unsealing process of the packer is complicated and requires multiple operations, which increases time and cost.
A resettable packer system is employed, which includes a sliding inner sleeve, a fixed outer sleeve and an expandable packer. Through the action of the pump, the expandable packer expands or contracts at the desired depth in the well, thereby achieving sealing and pumping operations of the packer.
The rapid securing and unsealing of the packer is realized, reducing the total time and related costs of pumping operations and improving operation efficiency.
Smart Images
Figure CN119948235A_ABST
Abstract
Description
Background Art
[0001] Hydrocarbon fluids are located in underground porous rock hydrocarbon-bearing formations (called "reservoirs") beneath the Earth's surface. In order to extract hydrocarbon fluids, wells may be drilled to gain access to the reservoirs. Drilling operations may include well construction activities, such as casing the wellbore after a section of the wellbore has been drilled. Here, the drill string may be pulled out of the wellbore, and a portion of the casing may be deployed and cemented in place to create fluid and mechanical isolation from the newly drilled formation.
[0002] Production tubing is then typically installed to recover reservoir fluids. In the process, the annular gap or space between the production tubing and the surrounding casing (or other tubing) is bridged by a production packer. In this way, the annular volume above the packer is effectively sealed from the annular volume below the packer to prevent or inhibit the migration of fluids or gases (of any type) between the lower and upper annular volumes. Typically, swellable packers are used to seal portions of a well. Swellable packers are typically designed to expand radially when fluid is injected into the packer. Summary of the invention
[0003] In general, in one aspect, one or more embodiments relate to a resettable packer system for pumping operations, comprising: a swellable packer that expands between the resettable packer system and the tubing wall or casing wall to form a seal in the well; and a pump that expands the swellable packer at a desired depth in the well when actuated. The resettable packer system also includes: an inner sleeve that includes a port for fluid passage; an outer sleeve that is connected to the pump and forms a sealed fluid chamber with the swellable packer when the port of the outer sleeve and the port of the inner sleeve are not aligned. In addition, the inner sleeve slides axially along the inner surface of the outer sleeve so that the port of the outer sleeve is aligned or not aligned with the port of the inner sleeve. In addition, when the pump is not working, the swellable packer shrinks.
[0004] In one or more embodiments, the swellable packer may be swellable from a first size where the swellable packer does not contact the tubing wall or the casing wall to a second size where the swellable packer contacts the tubing wall or the casing wall.
[0005] In general, in one aspect, one or more embodiments relate to a method for setting and unsealing a resettable packer system, the method comprising sliding an inner sleeve of the resettable packer system axially along the inner surface of an outer sleeve of the resettable packer system, thereby aligning and misaligning the ports of the inner sleeve with the ports of the outer sleeve. When the ports of the inner sleeve and the ports of the outer sleeve are aligned, fluid passes through the ports of the inner sleeve and the ports of the outer sleeve, and when the ports of the inner sleeve and the ports of the outer sleeve are misaligned, fluid is prevented from passing through the ports of the inner sleeve and the ports of the outer sleeve. The method also includes starting a pump of the resettable packer system at a desired depth in the well, pumping fluid into a sealing fluid chamber between the outer sleeve and the swellable packer by the started pump, thereby expanding the swellable packer, and sealing the well between the resettable packer system and the tubing wall or the casing wall by the swelled packer. In addition, the method also includes performing a pumping operation in the well and deactivating the pump, thereby shrinking the swellable packer. BRIEF DESCRIPTION OF THE DRAWINGS
[0006] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying drawings. For consistency, similar elements are represented by similar reference numerals in the various drawings. The sizes and relative positions of the elements in the drawings are not necessarily drawn to scale. For example, the shapes and angles of the various elements are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve the readability of the drawings.
[0007] Figure 1 An exemplary well having an electric submersible pump (ESP) completion design is shown in accordance with one or more embodiments.
[0008] Figure 2 An inverted ESP string is shown according to one or more embodiments.
[0009] Figure 3 A cross-sectional view of a resettable packer system according to one or more embodiments of the present disclosure is shown.
[0010] FIG. 4A to FIG. 4G An operational sequence of a system according to one or more embodiments is shown.
[0011] Figure 5 A cross-sectional view of a resettable packer system according to one or more embodiments of the present disclosure is shown.
[0012] 6A to 6F An operational sequence of a system according to one or more embodiments is shown.
[0013] Figure 7 A cross-sectional view of a resettable packer system according to one or more embodiments of the present disclosure is shown.
[0014] Figure 8A cross-sectional view of a resettable packer system according to one or more embodiments of the present disclosure is shown.
[0015] Fig. 9 A flow chart of a method according to one or more embodiments of the present disclosure is shown. DETAILED DESCRIPTION
[0016] In the following detailed description of embodiments of the present invention, many specific details are set forth in order to provide a more thorough understanding of the present invention. However, it is apparent to one of ordinary skill in the art that the present disclosure may be practiced without these specific details. In other cases, well-known features are not described in detail to avoid unnecessarily complicating the description.
[0017] Throughout this application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives of elements (i.e., any nouns in this application). The use of ordinal numbers is not intended to imply or create any particular order of elements, nor to limit any element to only a single element, unless explicitly disclosed, such as using the terms "before," "after," "single," and other such terms. Rather, the use of ordinal numbers is intended to distinguish between elements. As an example, a first element is different from a second element, and a first element may contain more than one element and be after (or before) a second element in the ordering of elements.
[0018] Furthermore, throughout the application, the terms "upper" and "lower" may be used to describe the location of an element in a well. In this regard, the term "upper" refers to an element that is disposed closer to the surface of the earth than a corresponding "lower" element when in a downhole position, while the term "lower" conversely describes an element that is disposed farther from the surface of the well than a corresponding "upper" element. Likewise, the term "axial" refers to an orientation substantially parallel to the well, while the term "radial" refers to an orientation perpendicular to the well.
[0019] In one or more embodiments, the present disclosure describes systems and methods for setting and unsetting a resettable packer system for pumping operations. Operations for a system deployed without a rig or cable are presented; however, the embodiments disclosed herein are also applicable to tubing-deployed pumping systems. The application of such a packer system is beneficial during installation of downhole equipment, where packers need to be set at different depths within the wellbore. For example, a resettable packer system can be used when lifting liquid from a fluid-filled well, where the depth needs to be changed to optimize the liquid lifting process. In one or more embodiments, the resettable packer system includes a sliding inner sleeve, a fixed outer sleeve, and an expandable packer. The techniques discussed in the present disclosure are beneficial in reducing the overall time of a pumping operation and, therefore, reducing the associated costs.
[0020] Figure 1An exemplary ESP system 100 is shown according to one or more embodiments. The ESP system 100 is used to assist in producing formation fluids 102 from a formation 104. Perforations 106 in a well casing 108 provide a conduit for the formation fluids 102 to enter a well 116 from the formation 104. The well 116 may be vertically oriented or deviated at an angle. Deviated wells 116 are well known in the art. The ESP system 100 includes a surface portion having surface equipment 110 and a downhole portion having an ESP string 112.
[0021] ESP string 112 is deployed on production tubing 117 in well 116, and surface equipment 110 is located at surface location 114. Surface location 114 is any location outside of well 116, such as the surface of the earth. Production tubing 117 extends to surface location 114 and is made of multiple pipes connected together to provide a conduit for formation fluids 102 to migrate to surface location 114.
[0022] The ESP string 112 may include a motor 118, a motor protector 120, a gas separator 122, a multistage centrifugal pump 124 (referred to herein as a "pump" 124), and a power cable 126. The ESP string 112 may also include various pipe sections of varying lengths to connect the components of the ESP string 112. The motor 118 is a downhole submersible motor 118 that provides power to the pump 124. The motor 118 may be a two-pole, three-phase, squirrel cage induction motor, a permanent magnet motor, or another suitable motor 118. The operating voltage, current, and horsepower ratings of the motor 118 may vary depending on the requirements of the operation.
[0023] The size of the motor 118 is dictated by the amount of power required by the pump 124 to lift an estimated volume of formation fluid 102 from the bottom of the well 116 to the surface location 114. The motor 118 is cooled by the formation fluid 102 flowing through the housing of the motor 118. The motor 118 is powered by a power cable 126. The power cable 126 is a conductive cable capable of transmitting information. The power cable 126 transfers energy from the surface equipment 110 to the motor 118. The power cable 126 may be a three-phase cable specifically designed for the downhole environment. The power cable 126 may be clamped to the ESP string 112 so as to restrict the movement of the power cable 126 in the well 116. In further embodiments, the ESP string 112 may have a hydraulic line, which is a pipe for hydraulic fluid. The hydraulic line may be used as a sensor to measure downhole parameters, such as the discharge pressure from the outlet of the pump 124.
[0024] The motor protector 120 is located above the motor 118 in the ESP string 112 (i.e., closer to the surface location 114). The motor protector 120 is a seal that houses a thrust bearing. The thrust bearing bears the axial thrust from the pump 124, thereby protecting the motor 118 from the axial thrust. The seal isolates the motor 118 from the formation fluid 102. The seal further equalizes the pressure in the annulus 128 with the pressure in the motor 118. The annulus 128 is the space between the casing 108 and the ESP string 112 in the well 116. The pump inlet 130 is the portion of the ESP string 112 where the formation fluid 102 enters the ESP string 112 from the annulus 128.
[0025] The pump inlet 130 is located above the motor protector 120 and below the pump 124. The depth of the pump inlet 130 is designed based on the formation 104 pressure, the estimated height of the formation fluid 102 in the annulus 128, and the optimization of the performance of the pump 124. If the formation fluid 102 has associated gas, a gas separator 122 may be installed in the ESP string 112 above the pump inlet 130 but below the pump 124. The gas separator 122 removes gas from the formation fluid 102 and separates the gas (in Figure 1 The gas 132 (depicted as separated gas 132) is injected into the annulus 128. If the volume of gas exceeds a specified limit, a gas treatment device can be installed below the gas separator 122 and above the pump inlet 130.
[0026] The pump 124 is located above the gas separator 122 and lifts the formation fluid 102 to the surface location 114. The pump 124 has a plurality of stages stacked on top of each other. Each stage includes a rotating impeller and a fixed diffuser. When the formation fluid 102 enters each stage, the formation fluid 102 passes through the rotating impeller to be centrifuged radially outward, thereby obtaining energy in the form of velocity.
[0027] The formation fluid 102 enters the diffuser and the velocity is converted into pressure. As the formation fluid 102 passes through each stage, the pressure continues to increase until the formation fluid 102 achieves a specified discharge pressure and has enough energy to flow to the surface location 114. Figure 1 The ESP string 112 shown in FIG. 1 may be described as a standard ESP string 112 , however, the term ESP string 112 may refer to a standard ESP string 112 or an inverted ESP string 112 without departing from the scope of the present invention.
[0028] In one or more embodiments, sensors may be installed at various locations along the ESP string 112 to collect downhole data, such as pump inlet pressure, discharge pressure, and temperature. Prior to installation, the number of stages is determined based on the estimated required discharge pressure. Over time, the pressure of the formation 104 decreases, and the height of the formation fluid 102 in the annulus 128 decreases. In these cases, the ESP string 112 may be removed and resized. Once the formation fluid 102 reaches the surface location 114, the formation fluid 102 flows through the wellhead 134 into the production equipment 136. The production equipment 136 may be any equipment capable of collecting or transporting the formation fluid 102, such as a pipeline or a tank.
[0029] The remainder of the ESP system 100 includes various surface equipment 110, such as an electric drive 137 and a pump control device 138, and a power source 140. The power source 140 provides energy to the motor 118 via a power cable 126. The power source 140 may be a commercial power distribution system or a portable power source such as a generator.
[0030] The pump control equipment 138 consists of various intelligent unit programmable controllers and drives that maintain the proper current supplied to the motor 118, such as a fixed frequency switchboard, a soft start controller, and a variable speed controller. The electric drive 137 may be a variable speed drive that reads the downhole data recorded by the sensors and can proportionally reduce or increase the speed of the motor 118 to optimize the efficiency and productivity of the pump 124. The electric drive 137 allows the pump 124 to operate continuously and intermittently, or to be shut down in the event of an operating problem.
[0031] Figure 2 An inverted ESP string 112 is shown according to one or more embodiments. For readability purposes, Figure 2 The ones shown in Figure 1 Components described in are not re-described and have the same description and purpose as described above. Figure 2 The inverted ESP string 112 shown in FIG. 1 has a pump 124 located downhole at the motor 118, while Figure 11, the pump 124 is located at an uphole position of the motor 118. In addition, the production tubing 117 of the inverted ESP string 112 design passes through the packer 142. The packer 142 is disposed within the casing 108 of the well 116. The motor 118, the ESP seal 119, and the pump 124 are connected to the production tubing 117 and are located at an uphole position of the packer 142. The packer 142 can be any packer 142 known in the art, such as a mechanical packer 142. The packer 142 seals the annulus 128 space between the inverted ESP string 112 and the casing 108. This prevents the formation fluid 102 from migrating past the packer 142 in the annulus 128.
[0032] ESP seal 119 may include one or more seals for preventing fluid from entering motor 118. According to one or more embodiments, ESP seal 119 may be similar to Figure 1 ESP seal 119 is connected to drain 176. Discharge 176 may include a plurality of holes 121 and may not be machined as part of pump 124. Holes 121 allow fluids (eg, formation fluids 102) to exit drain 176.
[0033] In this non-limiting example, the inverted ESP string 112 includes a motor head 123 and a shroud 125. The motor head 123 enables electrical connection between the power cable 126 and the motor 118 to occur in an environment where formation fluid 102 is not present. In addition, the motor head 123 extends into the shroud 125 so that the bore 121 of the motor head 123, the motor 118, the ESP seal 119, and the bore 121 of the drain 176 are encapsulated by the shroud 125. The shroud 125 is formed in a cylindrical shape surrounding the above-mentioned encapsulated elements of the inverted ESP string 112. The shroud 125 encapsulates these elements and isolates them from the external environment, and contains the flow of formation fluid 102 from the production tubing 117. The shroud 125 can be made of any durable material known in the art, such as steel.
[0034] The power cable 126 is connected to the portion of the motor head 123 that is located in the external environment outside the shroud 125 and is located at the uphole position of the packer 142. Therefore, the connection of the power cable 126 to the motor head 123 can be made in an environment without formation fluid 102.
[0035] According to one or more embodiments, formation fluid 102 enters well 116 through perforations 106 in casing 108. Formation fluid 102 travels up the wellbore using production tubing 117. Formation fluid 102 then enters pump 124, which is powered by motor 118. Here, pump 124 pumps formation fluid 102 through holes 121 of discharge port 176 into shroud 125. Formation fluid 102 then bypasses ESP seal 119 and motor 118 while inside shroud 125 and enters motor head 123 through holes 121 of motor head 123. Finally, formation fluid 102 flows from motor head 123 back into production tubing 117, where pumping pressure provided by pump 124 pushes formation fluid 102 to surface location 114.
[0036] In the ESP system 100, conventional procedures require the use of a plug to be run into the wellbore to set the packer 142. The plug within the production tubing 117 may be used to form a barrier to allow application of the pressure differential required to set the packer 142. Once the packer 142 is set, the plug must be retrieved, resulting in high costs and time.
[0037] The ESP system 100 has applications in various oilfield operations where high volume flow and boosting capabilities are desired. One application may be during the installation of a rig-less pumping system, such as when attempting to lift formation fluid 102 from a fluid-filled well 116 to a surface location 114. In some cases, when the pump 124 is connected to the packer 142, it may be desirable to change the setting depth of the packer 142 / pump 124, perhaps to optimize the liquid lift process. To accomplish this, a first operation is performed to retrieve the entire pumping system to the surface. Next, additional operations are required to unseal the packer 142 and deploy it to the new setting depth. Further operations are required to reinstall the pumping system back into the well 116, thereby latching into the packer 142 at the new setting depth. The above process increases the overall time and cost required to complete the operation and bring production online. Therefore, Figures 3 to 9 Embodiments disclosed herein present systems and methods for setting and unsetting a resettable packer system 144 for pumping operations, the resettable packer system 144 comprising a sliding inner sleeve 146, a fixed outer sleeve 148, and an expandable packer 150. The resettable packer system 144 can be set and unset multiple times in a single operation without the need to retrieve the entire pumping system, thereby minimizing the time and associated costs of pumping operations.
[0038] Figure 3A cross-sectional view of a resettable packer system 144 according to one or more embodiments of the present disclosure is shown. Here, the resettable packer system 144 includes a swellable packer 150, a pump 124, an outer sleeve 148, an inner sleeve 146, and a spring 152, and is configured to be attached to the downhole end of the ESP system 100 within the well 116. The resettable packer system 144 can be directly flanged or threaded to the downhole end of the ESP system 100. The swellable packer 150 can be formed of an elastomeric or flexible material suitable for expansion and contraction, such as Kevlar, a polymer, polyester, nanocellulose, or a natural material such as cotton, wool, silk, or linen. Therefore, the swellable packer 150 is configured to form a seal in the well 116 by expanding from the resettable packer system 144 to the wall of the tubing 117 or the wall of the casing 108. For example, the swellable packer 150 can be configured to form a seal in the well 116 by expanding from a first size in which the swellable packer 150 does not contact the tubing 117 wall or the casing 108 wall to a second size in which the swellable packer 150 contacts the tubing 117 wall or the casing 108 wall. The pump 124 disposed at the upper end of the resettable packer system 144 is configured to expand the swellable packer 150 at a desired depth in the well 116 when activated. Located below the pump 124 are an outer sleeve 148 and an inner sleeve 146 of the resettable packer system 144. The outer sleeve 148 and the inner sleeve 146 are both tubular and formed of a durable material such as steel. The outer sleeve 148 is rigidly fixed to the wedge 154 and the base 156 of the resettable packer system 144 by a threaded connection, while the inner sleeve 146 is connected to the spring 152 and can slide axially along the inner surface 158 of the outer sleeve 148. Additionally, the swellable packer 150 may be incorporated into the outer sleeve 148 during the manufacturing process of the resettable packer system 144 .
[0039] The spring 152 is disposed in the cavity between the inner sleeve 146 and the outer sleeve 148. In addition, the spring 152 can be formed of high carbon steel, alloy steel or stainless steel and is a compression spring 152. The cavity in which the spring 152 is located is isolated from the formation fluid 102 by rubber or elastomeric seals 160 above and below the spring 152. The stiffness and retracted length of the spring 152 are selected to match the spring force required to move the inner sleeve 146 based on the final desired setting depth and the properties of the formation fluid 102. The wedge 154 located at the upper end of the resettable packer system 144 limits the axial upward movement of the inner sleeve 146, while the base 156 located at the downhole end of the resettable packer system 144 limits the axial downward movement of the inner sleeve 146. The wedge 154 and the base 156 can also be formed of durable materials, such as steel.
[0040] In addition, both the outer sleeve 148 and the inner sleeve 146 include ports 162. These ports 162 are slots disposed within the outer sleeve 148 and the inner sleeve 146 and are configured for passage of formation fluid 102. When the ports 162 of the outer sleeve 148 and the inner sleeve 146 are aligned, the formation fluid 102 can travel between the swellable packer 150 and the bore 164 of the resettable packer system 144. However, when the ports 162 are not aligned, fluid communication between the bore 164 and the swellable packer 150 is lost due to the formation of a sealed fluid chamber 166 between the outer surface of the outer sleeve 148 and the interior of the swellable packer 150. The seal 160 is used to prevent the formation fluid 102 from passing through the gap between the outer sleeve 148 and the inner sleeve 146 when the ports 162 of the outer sleeve 148 and the inner sleeve 146 are not aligned. Additionally, an O-ring 168 of a rubber or elastomeric material is disposed between the base 156 and the outer sleeve 148 to prevent the formation fluid 102 from entering or exiting the system 144 .
[0041] The resettable packer system 144 also includes a control line 170, a check valve 172, and a pressure relief valve 174. The control line 170 may be a 1 / 8 inch diameter pipe for introducing the formation fluid 102 into the swellable packer 150 and is typically connected to a pressure supply source, which may be, for example, a vent 176. Thus, the packer system 144 is connected to a pump via the control line 170, which supplies pressurized fluid to the packer 150. The control line 170 and the swellable packer 150 are connected by the check valve 172. The check valve 172 is configured to control the flow 178 of the formation fluid 102 in a single direction. For the vent 176 and the swellable packer 150, the check valve 172 controls the flow direction 178 of the formation fluid 102 (e.g., FIG. 4C to FIG. 4F 176 to the swellable packer 150. In addition, if the pressure within the swellable packer 150 exceeds a pressure threshold, a pressure relief valve 174 disposed along the swellable packer 150 may be used to eject the formation fluid 102 from the fluid chamber 166. The pressure threshold is determined by the operator of the well 116 based on the design limits of the swellable packer 150 or the manufacturer's recommendations. In addition, the pressure relief valve 174 may be positioned along the upper surface or downhole surface of the swellable packer 150 so that the formation fluid 102 may escape into the production tubing 117 or casing 108.
[0042] FIG. 4A to FIG. 4G 1 shows the sequence of operations of the resettable packer system 144 according to one or more embodiments. Specifically, Figure 4AThe system 144 is shown at a surface location 114 and prior to installation of the system 144 within a well 116. Prior to being lowered downhole, the spring 152 presses the top surface 180 of the inner sleeve 146 against a portion of the wedge 154 that projects inwardly toward the bore 164 of the resettable packer system 144. In this initial position, the outer sleeve 148 and the port 162 of the inner sleeve 146 are not aligned.
[0043] As the resettable packer system 144 is lowered into the well 116 prior to the desired setting depth, the top surface 180 of the inner sleeve 146, which is exposed to the formation fluid 102, is subjected to a hydrostatic pressure that increases with depth. This hydrostatic pressure pushes the inner sleeve 146 downward, thereby compressing the spring 152 more than at the surface location 114. The upward force of the spring 152 on the inner sleeve 146 is balanced by a downward force that is the sum of the net hydrostatic force on the inner sleeve 146, the frictional resistance of the seal 160 against the inner surface 158 of the outer sleeve 148, and the net weight of the inner sleeve 146.
[0044] exist Figure 4B , the system 144 is at the final setting depth. Here, the fluid static pressure (P 深度，无流动 ) is higher than the hydrostatic pressure at the surface location 114. As a result, the inner sleeve 146 is pushed downwardly so that the bottom surface of the inner sleeve 146 abuts the base 156. In this position, the ports 162 of the outer sleeve 148 and the inner sleeve 146 are aligned. In turn, there is fluid communication between the bore 164 of the resettable packer system 144 and the fluid chamber 166 disposed between the outer sleeve 148 and the swellable packer 150. As a result, the formation fluid 102 begins to fill the fluid chamber 166.
[0045] At the desired final setting depth of the resettable packer system 144, the hydrostatic pressure (P 深度，无流动 ) is highest, and therefore the compression of spring 152 is also greatest at this time. When pump 124 is activated, most of the formation fluid 102 flows upward through the holes 164 of the resettable packer system 144 toward the ESP system 100 due to the high suction pressure generated by pump 124. Now, the new pressure (P) acting on the top surface 180 of the inner sleeve 146 at the setting depth is 深度，流动 ) becomes smaller than (P 深度，无流动 ). This in turn creates an imbalance of force and causes the spring 152 to push the inner sleeve 146 upward, thereby causing the outer sleeve 148 and the port 162 of the inner sleeve 146 to be misaligned, such as Figure 4C In this position, the formation fluid 102 within the swellable packer 150 is sealed from the formation fluid 102 located in the well 116 and in the bore 164 of the resettable packer system 144 .
[0046] The control line 170 of the resettable packer system 144 is connected to the drain 176. Figure 4D In the embodiment of the present invention, the pressure generated by the pump 124 exceeds the pressure in the fluid chamber 166. Therefore, the high-pressure formation fluid 102 flowing from the pump 124 to the discharge port 176 is introduced into the fluid chamber 166 through the check valve 172. As a result, the swellable packer 150 is forced to expand until it contacts a solid surface (e.g., the wall of the tubing 117 or the wall of the casing 108). The swellable packer 150 then provides isolation between the high-pressure formation fluid 102 above the swellable packer 150 and the low-pressure formation fluid 102 below the swellable packer 150.
[0047] The pressure threshold of the swellable packer 150 is determined based on the required sealing force before installing the resettable packer system 144. The required sealing force is a function of the total weight of the ESP system 100, the contact surface area of the swellable packer 150 with the tubing 117 wall or the casing 108 wall, and additional specifications familiar to those skilled in the art. In addition, the pump 124 is sized to ensure that it can supply at least the required pressure in the fluid chamber 166. If for any reason the pressure in the fluid chamber 166 exceeds the pressure threshold, the pressure relief valve 174 will open to discharge the excess formation fluid 102 into the well 116, thereby reducing the pressure in the fluid chamber 166 to the design limit.
[0048] Figure 4E The system 144 is shown if a change in the desired setting depth is required. Here, the pump 124 is turned off, which immediately causes a change in the direction of the flow 178. At this point, the ports 162 of the outer sleeve 148 and the inner sleeve 146 are still misaligned, causing the high pressure formation fluid 102 to remain trapped within the fluid chamber 166.
[0049] As the pump 124 is deactivated, the static pressure at the top surface 180 of the inner sleeve 146 will begin to increase toward (P 深度，无流动 ) increases, similar to Figure 4B The situation shown in (P 深度，无流动 ) will push the inner sleeve 146 downward against the spring force, thereby causing the ports 162 of the outer sleeve 148 and the inner sleeve 146 to align with each other. In turn, fluid communication between the fluid chamber 166 and the hole 164 is reestablished. As a result, the high-pressure formation fluid 102 sealed in the fluid chamber 166 is released into the hole 164, thereby causing the swellable packer 150 to contract and break contact with the wall of the tubing 117 or the wall of the casing 108, as shown in FIG. Figure 4F shown.
[0050] After the swellable packer 150 is deflated, the resettable packer system 144 may be removed from the well 116 and lifted up or down to a new desired setting depth. To reset the swellable packer 150, repeat FIG. 4A to FIG. 4D After the entire pumping operation is completed, you can perform Figure 4E and Figure 4F The steps described in the above description can be repeated and the entire system 144 can be retracted to the ground position 114. In addition, at the ground position 114, the outer sleeve 148 and the inner sleeve 146 are positioned at Figure 4G It is shown in Figure 4A The outer sleeve 148 and the inner sleeve 146 are positioned the same.
[0051] Figure 5 Another embodiment of a resettable packer system 144 according to one or more embodiments of the present disclosure is shown. For the sake of readability, the description of the components already described in the Figure 3 and as described in Figure 4 Figure 5 , and these components have the same description and purpose as outlined above. However, in this embodiment, the drag force generated by the flow 178 of the formation fluid 102 is used to slide the inner sleeve 146 of the resettable packer system 144.
[0052] Here, a top surface 180 of the inner sleeve 146 disposed between the outer sleeve 148 and the wedge 154 is sealed from the formation fluid 102 by the seal 160. In addition, the downhole end of the inner sleeve 146 includes a weighted portion 181 that is exposed to the formation fluid 102. The weighted portion 181 of the inner sleeve 146 protrudes from the inner sleeve 146 toward the bore 164 of the resettable packer system 144. In addition, the weighted portion 181 can be formed of a similar material as the inner sleeve 146, or of a denser or heavier material.
[0053] Similar to Figures 3 to 4G 146 and the outer sleeve 148 are aligned, the inner sleeve 146 rests on the upper surface of the base 156, thereby allowing fluid communication between the bore 164 and the fluid chamber 166 of the resettable packer system 144. The alignment of the ports 162 is achieved by the weight of the inner sleeve 146 and the weighted portion 181. That is, the total downward force generated by the combined weight of the inner sleeve 146 and the weighted portion 181 (including the frictional resistance of the seal 160 against the inner surface 158 of the outer sleeve 148) is greater than the net hydrostatic force acting upward on the downhole surface of the inner sleeve 146.
[0054] 6A to 6F The operation sequence of the system according to one or more embodiments is shown. Specifically, Fig. 6AThe resettable packer system 144 is shown at the final setting depth within the well 116. In addition, Fig. 6A The layout shown in is the same as the layout of the resettable packer system 144 at the surface location 114 before and during installation of the resettable packer system 144 in the well 116. In addition, Fig. 6A The resettable packer system 144 is shown before the pump 124 is turned on.
[0055] exist Figure 6B In the embodiment of the present invention, when the pump 124 is started, the formation fluid 102 flows to the pump 124 through the hole 164 of the resettable packer system 144 due to the suction force generated by the pump 124. Therefore, the hydrostatic pressure upstream of the weighted portion 181 is greater than the hydrostatic pressure downstream of the weighted portion 181. The combined cross-sectional area of the weighted portion 181 and the portion of the inner sleeve 146 that contacts the weighted portion 181 is significantly greater than the cross-sectional area of the inner sleeve 146 just after the weighted portion 181. These differences in hydrostatic pressure and cross-sectional area produce a net upward force or drag on the inner sleeve 146. In turn, the drag force causes the inner sleeve 146 to lift and slide upward within the resettable packer system 144, thereby misaligning the port 162 of the inner sleeve 146 with the port 162 of the outer sleeve 148. Subsequently, all flow 178 of formation fluid 102 travels through the bore 164 of the resettable packer system 144, and the formation fluid 102 located within the fluid chamber 166 is now trapped. If more flow 178 is drawn by the pump 124, the drag force increases, causing the inner sleeve 146 to be pushed further upward toward the wedge 154.
[0056] Similar to Figure 4D The process described in Figure 6C In the process, the swellable packer 150 is forced to swell until it contacts a solid surface, such as the wall of the tubing 117 or the wall of the casing 108. As a result, the swellable packer 150 provides isolation between the high-pressure formation fluid 102 above the swellable packer 150 and the low-pressure formation fluid 102 below the swellable packer 150. If the pressure within the fluid chamber 166 exceeds the pressure threshold, the pressure relief valve 174 opens to discharge the excess formation fluid 102 into the well 116 and reduce the pressure within the fluid chamber 166 to the desired design limit.
[0057] If it is necessary to change the set depth of the resettable packer system 144 in the well 116, first, the pump 124 is shut down and the upward flow 178 of the formation fluid 102 is stopped. Fig.6D. At this point, the port 162 of the inner sleeve 146 and the port 162 of the outer sleeve 148 are still misaligned. In addition, high-pressure formation fluid 102 is still trapped in the fluid chamber 166 of the resettable packer system 144. After the pump 124 is turned off, the upward drag force is reduced to zero. In turn, the combined weight of the inner sleeve 146 and the weighted portion 181 causes the inner sleeve 146 to slide downward within the resettable packer system 144. Therefore, the inner sleeve 146 continues to slide downward until the downhole end of the inner sleeve 146 abuts against the base 156 of the resettable packer system 144, as shown in FIG. Fig. 6E As shown. In this position, the port 162 of the inner sleeve 146 and the port 162 of the outer sleeve 148 are aligned with each other. Therefore, the fluid communication between the fluid chamber 166 and the hole 164 is reestablished. As a result, the high pressure formation fluid 102 previously disposed in the fluid chamber 166 is released into the hole 164, causing the swellable packer 150 to shrink and break contact with the wall of the casing 108 or the wall of the tubing 117.
[0058] exist Fig. 6F , the fluid chamber 166 has been depressurized to the downhole ambient pressure (similar to Fig. 6A The entire bottom hole assembly can be raised or lowered to the new desired setting depth and the setting can be repeated. Figure 6B and Figure 6C The steps shown are to re-set the resettable packer system 144. When the entire pumping operation has been completed, the Fig.6D and Fig. 6E The steps shown in the figure can be used to retract the entire system 144 to the ground position 114. The position of the inner sleeve 146 and the outer sleeve 148 at the ground position 114 is Fig. 6F It is shown in Fig. 6A The same as in.
[0059] because Figures 5 to 6F The illustrated embodiment relies on gravity to ensure that the inner sleeve 146 slides downwardly to align the port 162 of the inner sleeve 146 with the port 162 of the outer sleeve 148, and therefore the applicability of this particular embodiment may be limited to vertical wells 116 or wells 116 that deviate from vertical by no more than 30 to 45 degrees. In order to ensure that the inner sleeve 146 can slide within the resettable packer system 144 in the well 116 in a manner that deviates from the vertical by more than 30 to 45 degrees, a method such as Figure 7An additional embodiment of a resettable packer system 144 is shown. In this particular embodiment, a spring 152 located within a sealed cavity between a wedge 154 and an outer sleeve 148 is used to ensure that, regardless of well 116 deflection, once the drag force is removed, the inner sleeve 146 can still slide within the resettable packer system 144. Thus, the spring 152 is attached to a top surface 180 of the inner sleeve 146. The spring force of the spring 152 pushes the inner sleeve 146 downhole to contact the base 156 of the resettable packer system 144, thereby ensuring that even in a very deflected well, the port 162 can be aligned and the fluid chamber 166 can be sufficiently depressurized to facilitate resetting the system 144.
[0060] Figure 8 Another embodiment of a resettable packer system 144 is shown. In this embodiment, a piston or a plurality of pistons 182 are utilized to slide the inner sleeve 146. The plurality of pistons 182 may be formed of mild steel or an aluminum alloy, and each piston 182 includes a cylindrical body and a plunger. The cylindrical body of each piston 182 may be attached to the base 156 or wedge 154 of the resettable packer system 144, and the plunger of each piston 182 may be attached to the top surface 180 or the bottom surface of the inner sleeve 146. The plurality of pistons 182 are configured to control the position of the inner sleeve 146 within the resettable packer system 144, thereby aligning or misaligning the ports 162 of the outer sleeve 148 and the inner sleeve 146.
[0061] exist Figure 8 In the illustrated embodiment, the plurality of pistons 182 are double-acting pistons that, when actuated, force the plunger to retract into or pop out of the cylindrical body. In other embodiments of the resettable packer system 144, another form of piston 182, such as a single-acting piston, may be utilized that moves in one direction when actuated. In addition, the plurality of pistons 182 may be hydraulically actuated via a hydraulic line of the ESP string 112 and remotely controlled at the surface location 114. Upon actuation of the plurality of pistons 182, each plunger in the plurality of pistons 182 similarly moves within or away from the cylindrical body of the plurality of pistons 182, thereby moving the attached inner sleeve 146 so that the port 162 of the inner sleeve 146 is aligned or misaligned with the port 162 of the outer sleeve 148.
[0062] Fig. 9 A flow chart illustrating a method for setting and unsetting a resettable packer system 144 is shown. Although the sequential Fig. 9 In the individual flow chart blocks of the embodiment, it will be appreciated by those skilled in the art that some or all of these blocks may be performed in different orders, may be combined or omitted, and some or all of these blocks may be performed in parallel. In addition, these blocks may be performed actively or passively.
[0063] In box 201, the inner sleeve 146 of the resettable packer system 144 slides along the inner surface 158 of the outer sleeve 148 of the resettable packer system 144. This occurs first when the hydrostatic force pushes the inner sleeve 146 downward as the resettable packer system 144 is lowered to a desired depth within the well 116. Once the resettable packer system 144 reaches the desired depth, the force on the inner sleeve 146 has caused the inner sleeve 146 to slide to a position such that the port 162 of the inner sleeve 146 and the port 162 of the outer sleeve 148 are aligned. In turn, the bore 164 of the resettable packer system 144 and the interior of the swellable packer 150 are in fluid communication. The formation fluid 102 disposed within the bore 164 can flow into the fluid chamber 166 with the inner sleeve 146 in this position.
[0064] In box 202, at the desired depth, the pump 124 of the resettable packer system 144 is electrically activated by the operator of the well 116 at the surface location 114. Subsequently, due to the high suction pressure generated by the pump 124, most of the formation fluid 102 flows upward through the holes 164 of the resettable packer system 144 toward the ESP system 100. In addition, the inner sleeve 146 slides upward, thereby misaligning the ports 162 of the outer sleeve 148 and the inner sleeve 146. This, in turn, seals the fluid chamber 166 and forces the flow 178 of the formation fluid 102 upward through the holes 164.
[0065] In box 203, the formation fluid 102 is pumped into the sealed fluid chamber 166 by the pump 124. The formation fluid 102 traveling upward through the hole 164 reaches the discharge port 176 through the pump 124. The discharge port 176 is connected to the swellable packer 150 through the control line 170. When the pressure generated by the pump 124 is greater than the pressure within the fluid chamber 166 of the swellable packer 150, the high-pressure formation fluid 102 flowing from the pump 124 to the discharge port 176 is introduced into the fluid chamber 166 through the control line 170. The formation fluid 102 passes through the check valve 172 when leaving the control line 170 and before entering the fluid chamber 166. The check valve 172 ensures that the formation fluid 102 travels only in the direction from the discharge port 176 to the swellable packer 150. In addition, when the formation fluid 102 is pumped into the fluid chamber 166, the swellable packer 150 begins to expand.
[0066] In box 204, when the swellable packer 150 is fully expanded, the swellable packer 150 seals the well 116 between the resettable packer system 144 and the wall of the tubing 117 or the wall of the casing 108. The swellable packer 150 then provides isolation between the high pressure formation fluid 102 above the swellable packer 150 and the low pressure formation fluid 102 below the swellable packer 150.
[0067] In box 205, a pumping operation may be performed in the well 116. With the swellable packer 150 fully inflated, the pressure of the formation fluid 102 within the fluid chamber 166 is similar to the pressure of the pump 124. Thus, the formation fluid 102 pumped from below the swellable packer 150 by the pump 124 is now discharged through the discharge port 176 into the production tubing 117 above the swellable packer 150. This formation fluid 102 then travels to the surface location 114 to be produced.
[0068] In box 206, the pump 124 is electrically deactivated by the operator of the well 116 at the surface location 114. This may occur when the desired setting depth of the resettable packer system 144 needs to be changed, or if the pumping operation is completed and the resettable packer system 144 needs to be removed from the well 116. After the pump 124 is turned off, the direction of the flow 178 of the formation fluid 102 changes. In addition, the pressure on the inner sleeve 146 increases, causing the inner sleeve 146 to slide downward, thereby aligning the outer sleeve 148 and the port 162 of the inner sleeve 146. Therefore, the fluid communication between the hole 164 and the fluid chamber 166 is reestablished, and the high pressure formation fluid 102 disposed in the fluid chamber 166 flows out into the hole 164 and flows back downhole. When the formation fluid 102 leaves the fluid chamber 166, the swellable packer 150 contracts, thereby breaking contact with the wall of the tubing 117 or the wall of the casing 108. The resettable packer system 144 may then be removed from the well 116 and either lifted up or down to a new desired setting depth.
[0069] Thus, the disclosed above embodiments relate to systems and methods for minimizing the time and associated costs of pumping operations. The above embodiments can be set and unset multiple times in a single operation without the need to retrieve the entire pumping system. The disclosed systems and methods for setting and unsetting the resettable packer system 144 for pumping operations advantageously facilitate faster activation and deactivation of the packer 150, which reduces the time to deploy the bottom hole assembly to different desired depths. In addition, the disclosed systems and methods advantageously accommodate large variations in flow rates (using the ESP system 100) to lift formation fluids 102 from the well 116.
[0070] Although only a few embodiments of the present invention have been described in detail above, those skilled in the art will readily appreciate that many modifications may be made in the exemplary embodiments without substantially departing from the present invention. Therefore, all such modifications are intended to be included within the scope of the present disclosure as defined by the appended claims.
Claims
1. A resettable packer system (144) for pumping operation, comprising: a swellable packer (150) configured to swell between the resettable packer system (150) and a tubing wall or a casing wall to form a seal in the well (116); a pump (124) configured to, when activated, expand the swellable packer (150) at a desired depth within the well (116); an inner sleeve (146) comprising a port (162) for passage of a fluid (102); an outer sleeve (148) connected to the pump (124) and configured to form a sealed fluid chamber (166) with the swellable packer (150) when the port (162) of the outer sleeve (148) and the port (162) of the inner sleeve (146) are not aligned; wherein the inner sleeve (146) is configured to slide axially along the inner surface (158) of the outer sleeve (148) so that the port (162) of the outer sleeve (148) is aligned or misaligned with the port (162) of the inner sleeve (146); and Wherein, when the pump (124) is not working, the expandable packer (150) shrinks.
2. The resettable packer system (144) of claim 1, wherein: The pump (124), when activated, is configured to expand the swellable packer (150) by supplying pressurized fluid to the swellable packer (150) via a control line (170) connecting the pump (124) and the swellable packer (150).
3. The resettable packer system (144) according to claim 1 or 2, wherein: When the port (162) of the outer sleeve (148) is aligned with the port (162) of the inner sleeve (146), the fluid chamber (166) is in fluid communication with the well (116).
4. The resettable packer system (144) according to any one of claims 1 to 3, further comprising a pressure relief valve (174), wherein the pressure relief valve (174) is configured to eject the fluid (102) from the fluid chamber (166) when the pressure of the fluid chamber (166) exceeds a pressure threshold.
5. The resettable packer system (144) according to any one of claims 2 to 4 when dependent on claim 2, further comprising a check valve (172), wherein the check valve (172) is configured to control the direction of fluid flow so that the fluid (102) flows only from the control line (170) into the fluid chamber (166).
6. The resettable packer system (144) according to any one of claims 1 to 5, further comprising a plurality of seals (160), wherein the plurality of seals (160) are configured to prevent the fluid (102) from flowing through a gap provided between the outer sleeve (148) and the inner sleeve (146).
7. The resettable packer system (144) according to any one of claims 1 to 6, further comprising a spring (152) configured to slide the inner sleeve (146).
8. The resettable packer system (144) according to any one of claims 1 to 7, wherein: The inner sleeve (146) also includes a weighted portion (181) configured to increase the weight of the inner sleeve (146) and expand the cross-sectional area of the downhole end of the inner sleeve (146).
9. The resettable packer system (144) according to any one of claims 1 to 8, further comprising a wedge (154), which is configured to limit the axial movement of the inner sleeve (146) toward the ground position and connect the outer sleeve (148) and the pump (124).
10. The resettable packer system (144) according to any one of claims 1 to 9, further comprising a base (156) configured to limit axial movement of the inner sleeve (146) toward a downhole end of the well (116).
11. The resettable packer system (144) of claim 10, wherein: The outer sleeve (148) is rigidly secured to the base (156) within the resettable packer system (144).
12. A method for setting and unsetting a resettable packer system (144), comprising: axially sliding an inner sleeve (146) of the resettable packer system (144) along an inner surface (158) of an outer sleeve (148) of the resettable packer system (144) to align and misalign a port (162) of the inner sleeve (146) with a port (162) of the outer sleeve (148), wherein when the port (162) of the inner sleeve (146) and the port (162) of the outer sleeve (148) are aligned, the fluid (102) passes through the port (162) of the inner sleeve (146) and the port (162) of the outer sleeve (148), and when the port (162) of the inner sleeve (146) and the port (162) of the outer sleeve (148) are not aligned, the fluid (102) is prevented from passing through the port (162) of the inner sleeve (146) and the port (162) of the outer sleeve (148); activating a pump (124) of the resettable packer system (144) at a desired depth in the well (116); pumping the fluid (102) into a sealed fluid chamber (166) between the outer sleeve (148) and the swellable packer (150) by the activated pump (124), thereby expanding the swellable packer (150); sealing the well (116) between the resettable packer system (144) and the tubing wall or casing wall by means of the swellable packer (150); performing a pumping operation within the well (116); and The pump (124) is deactivated, thereby causing the swellable packer (150) to deflate.
13. The method according to claim 12, wherein: Prior to sliding the inner sleeve (146), the resettable packer system (144) is lowered into the well (116) to the desired depth.
14. The method according to claim 13, wherein: Prior to lowering the resettable packer system (144) to the desired depth, the top surface (180) of the inner sleeve (146) rests on a wedge (154) connecting the outer sleeve (148) and the pump (124).
15. The method according to claim 14, wherein: When the top surface (180) of the inner sleeve (146) rests on the wedge (154), the port (162) of the inner sleeve (146) and the port (162) of the outer sleeve (148) are misaligned.
16. The method according to any one of claims 13 to 15, wherein: When the resettable packer system (144) is lowered into the well (116) to the desired depth, the fluid (102) applies pressure along the inner sleeve (146), thereby causing the inner sleeve (146) to slide downward, thereby aligning the port (162) of the inner sleeve (146) and the port (162) of the outer sleeve (148).
17. The method according to claim 16, wherein: When the port (162) of the inner sleeve (146) is aligned with the port (162) of the outer sleeve (148), the fluid chamber (166) is filled with the fluid (102).
18. The method according to any one of claims 12 to 17, wherein: After the pump (124) of the resettable packer system (144) is activated at a desired depth in the well (116), the port (162) of the inner sleeve (146) is misaligned with the port (162) of the outer sleeve (148), thereby sealing the fluid (102) within the fluid chamber (166).
19. The method according to any one of claims 12 to 18, wherein: Deactivating the pump (124) also includes: determining the desired depth to change the resettable packer system (144) and aligning the port (162) of the inner sleeve (146) with the port (162) of the outer sleeve (148) so that the fluid (102) leaves the fluid chamber (166), thereby causing the expandable packer (150) to shrink and disengage from the tubing wall or casing wall.
20. The method of claim 19, further comprising activating the pump (124) and resuming the pumping operation after repositioning the resettable packer system (144) at a new desired depth.