BACKGROUND

[0001] Hydrocarbon fluids are located below the surface of the Earth in subterranean porous rock hydrocarbon-bearing formations called “reservoirs.” In order to extract the hydrocarbon fluids, wells may be drilled to gain access to the reservoirs. Drilling operations may include well construction activities, such as casing the wellbore, subsequent to completion of drilling a section of the wellbore. Here, the drill string may be pulled out of the wellbore and a section of casing may be deployed and cemented into place to create fluid and mechanical isolation from the newly drilled formation.

[0002] Production tubing is then typically installed for the purpose of recovering reservoir fluids. In the process, an annular gap or space between the production tubing and surrounding casing (or other tubular) is bridged via a production packer. In so doing, an annular volume above the packer is effectively sealed off from an annular volume below the packer to prevent or inhibit migration of fluids or gases (of any type) between the lower and upper annular volumes. Commonly, inflatable packers are utilized to seal off portions of a well. Inflatable packers are generally designed to radially expand when fluid is injected into the packer.

SUMMARY

[0003] In general, in one aspect, one or more embodiments relate to a resettable packer system for pumping operations that includes an inflatable packer that expands between the resettable packer system and a tubing wall or a casing wall, thereby creating a seal in a well, and a pump that inflates the inflatable packer at a desired depth within the well when activated. The resettable packer system further includes an inner sleeve that includes ports for a fluid to pass through, an outer sleeve that is connected to the pump and creates a sealed fluid chamber with the inflatable packer when ports of the outer sleeve and the ports of the inner sleeve are misaligned. In addition, the inner sleeve slides axially along an inner surface of the outer sleeve, thereby aligning or misaligning the ports of the outer sleeve with the ports of the inner sleeve. Further, the inflatable packer contracts when the pump is inactive.

[0004] In one or more embodiments, the inflatable packer may expand from a first size, at which the inflatable packer does not contact the tubing wall or the casing wall, to a second size, at which the inflatable 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 unsetting a resettable packer system that includes sliding an inner sleeve of the resettable packer system axially along an inner surface of an outer sleeve of the resettable packer system, thereby aligning and misaligning ports of the inner sleeve and ports of the outer sleeve. When the ports of the inner sleeve and the ports of the outer sleeve align, a 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 misalign, the fluid is prevented from passing through the ports of the inner sleeve and the ports of the outer sleeve. The method further includes activating a pump of the resettable packer system at a desired depth in a well, pumping the fluid into a sealed fluid chamber between the outer sleeve and an inflatable packer by the activated pump, thereby inflating the inflatable packer, and sealing the well between the resettable packer system and a tubing wall or a casing wall by the inflated packer. In addition, the method further includes performing a pumping operation within the well and deactivating the pump, thereby contracting the inflatable packer.

BRIEF DESCRIPTION OF DRAWINGS

[0006] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility.

[0007] Figure 1 shows an exemplary well with an Electrical Submersible Pump (ESP) completion design in accordance with one or more embodiments. [0008] Figure 2 shows an inverted ESP string in accordance with one or more embodiments.

[0009] Figure 3 shows a cross-sectional view of a resettable packer system in accordance with one or more embodiments of the present disclosure.

[0010] Figures 4A-4G depict the operational sequence of the system in accordance with one or more embodiments.

[0011] Figure 5 shows a cross-sectional view of a resettable packer system in accordance with one or more embodiments of the present disclosure.

[0012] Figures 6A-6F depict the operational sequence of the system in accordance with one or more embodiments.

[0013] Figure 7 shows a cross-sectional view of a resettable packer system in accordance with one or more embodiments of the present disclosure.

[0014] Figure 8 shows a cross-sectional view of a resettable packer system in accordance with one or more embodiments of the present disclosure.

[0015] Figure 9 shows a flowchart of a method in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

[0016] In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well known features have not been described in detail to avoid unnecessarily complicating the description.

[0017] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not intended to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

[0018] In addition, throughout the application, the terms “upper” and “lower” may be used to describe the position of an element in a well. In this respect, the term “upper” denotes an element 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 disposed further away 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 orthogonal to the well.

[0019] In one or more embodiments, this disclosure describes systems and methods of setting and unsetting a resettable packer system for pumping operations. The operation for a rigless or cable deployed system is presented; however, embodiments disclosed herein are also applicable to tubing deployed pumping systems. The application of this packer system is beneficial during downhole equipment installation, where a packer is required to be set at different depths within a wellbore. For example, the resettable packer system may be used when lifting liquid from a loaded 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 inflatable packer. The techniques discussed in this disclosure are beneficial in reducing the total time of pumping operations and, thus, the associated costs.

[0020] Figure 1 shows an exemplary ESP system 100 in accordance with one or more embodiments. The ESP system 100 is used to help produce formation fluids 102 from a formation 104. Perforations 106 in the well casing 108 provide a conduit for the formation fluids 102 to enter the well 116 from the formation 104. The well 116 may be of vertical orientation or deviated at an angle. A deviated well 116 is 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] The ESP string 112 is deployed in a well 116 on production tubing 117 and the surface equipment 110 is located on a surface location 114. The surface location 114 is any location outside of the well 116, such as the Earth’s surface. The production tubing 117 extends to the surface location 114 and is made of a plurality of tubulars connected together to provide a conduit for formation fluids 102 to migrate to the surface location 114.

[0022] The ESP string 112 may include a motor 118, a motor protector 120, a gas separator 122, a multi-stage centrifugal pump 124 (herein called a “pump” 124), and a power cable 126. The ESP string 112 may also include various pipe segments of different 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 electric motor, permanent magnet motor, or another suitable motor 118. The motor’s 118 operating voltages, currents, and horsepower ratings may change depending on the requirements of the operation.

[0023] The size of the motor 118 is dictated by the amount of power that the pump 124 requires to lift an estimated volume of formation fluids 102 from the bottom of the well 116 to the surface location 114. The motor 118 is cooled by the formation fluids 102 passing over the motor 118 housing. The motor 118 is powered by the power cable 126. The power cable 126 is an electrically conductive cable that is capable of transferring 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 electric cable that is specially designed for downhole environments. The power cable 126 may be clamped to the ESP string 112 in order to limit power cable 126 movement in the well 116. In further embodiments, the ESP string 112 may have a hydraulic line that is a conduit for hydraulic fluid. The hydraulic line may act as a sensor to measure downhole parameters such as discharge pressure from the outlet of the pump 124.

[0024] Motor protectors 120 are located above (i.e., closer to the surface location 114) the motor 118 in the ESP string 112. The motor protectors 120 are a seal section that houses a thrust bearing. The thrust bearing accommodates axial thrust from the pump 124 such that the motor 118 is protected from axial thrust. The seals isolate the motor 118 from formation fluids 102. The seals further equalize the pressure in the annulus 128 with the pressure in the motor 118. The annulus 128 is the space in the well 116 between the casing 108 and the ESP string 112. The pump intake 130 is the section of the ESP string 112 where the formation fluids 102 enter the ESP string 112 from the annulus 128.

[0025] The pump intake 130 is located above the motor protectors 120 and below the pump 124. The depth of the pump intake 130 is designed based off of the formation 104 pressure, estimated height of formation fluids 102 in the annulus 128, and optimization of pump 124 performance. If the formation fluids 102 have associated gas, then a gas separator 122 may be installed in the ESP string 112 above the pump intake 130 but below the pump 124. The gas separator 122 removes the gas from the formation fluids 102 and injects the gas (depicted as separated gas 132 in Figure 1) into the annulus 128. If the volume of gas exceeds a designated limit, a gas handling device may be installed below the gas separator 122 and above the pump intake 130.

[0026] The pump 124 is located above the gas separator 122 and lifts the formation fluids 102 to the surface location 114. The pump 124 has a plurality of stages that are stacked upon one another. Each stage contains a rotating impeller and stationary diffuser. As the formation fluids 102 enter each stage, the formation fluids 102 pass through the rotating impeller to be centrifuged radially outward gaining energy in the form of velocity.

[0027] The formation fluids 102 enter the diffuser, and the velocity is converted into pressure. As the formation fluids 102 pass through each stage, the pressure continually increases until the formation fluids 102 obtain the designated discharge pressure and has sufficient energy to flow to the surface location 114. The ESP string 112 outlined in Figure 1 may be described as a standard ESP string 112, however, the term ESP string 112 may be referring to a standard ESP string 112 or an inverted ESP string 112 without departing from the scope of the disclosure herein.

[0028] In one or more embodiments, sensors may be installed in various locations along the ESP string 112 to gather downhole data such as pump intake pressures, discharge pressures, and temperatures. The number of stages is determined prior to installation based of the estimated required discharge pressure. Over time, the formation 104 pressure may decrease and the height of the formation fluids 102 in the annulus 128 may decrease. In these cases, the ESP string 112 may be removed and resized. Once the formation fluids 102 reach the surface location 114, the formation fluids 102 flow through the wellhead 134 into production equipment 136. The production equipment 136 may be any equipment that can gather or transport the formation fluids 102 such as a pipeline or a tank.

[0029] The remainder of the ESP system 100 includes various surface equipment 110 such as electric drives 137 and pump control equipment 138 as well as an electric power supply 140. The electric power supply 140 provides energy to the motor 118 through the power cable 126. The electric power supply 140 may be a commercial power distribution system or a portable power source such as a generator.

[0030] The pump control equipment 138 is made up of an assortment of intelligent unit- programmable controllers and drives which maintain the proper flow of electricity to the motor 118 such as fixed-frequency switchboards, soft-start controllers, and variable speed controllers. The electric drives 137 may be variable speed drives which read the downhole data, recorded by the sensors, and may scale back or ramp up the motor 118 speed to optimize the pump 124 efficiency and production rate. The electric drives 137 allow the pump 124 to operate continuously and intermittently or be shut-off in the event of an operational problem.

[0031] Figure 2 shows an inverted ESP string 112 in accordance with one or more embodiments. Components shown in Figure 2 that have been described in Figure 1 have not been redescribed for purposes of readability and have the same description and purpose as outlined above. The inverted ESP string 112 shown in Figure 2 has the pump 124 located downhole from the motor 118, whereas in Figure 1, the pump 124 is located up hole from the motor 118. Further, the production tubing 117 of the inverted ESP string 112 design traverses a packer 142. The packer 142 is set within the casing 108 of the well 116. A motor 118, an ESP seal 119, and a pump 124 are connected to the production tubing 117 and are located up hole from the packer 142. The packer 142 may be any packer 142 known in the art such as a mechanical packer 142. The packer 142 seals the annulus 128 space located between the inverted ESP string 112 and the casing 108. This prevents the formation fluids 102 from migrating past the packer 142 in the annulus 128.

[0032] The ESP seal 119 may contain one or more seals used to prevent fluid from entering the motor 118. In accordance with one or more embodiments, the ESP seal 119 may be similar to the motor protectors 120 as described in Figure 1. The ESP seal 119 is connected to the discharge 176. The discharge 176 may include a plurality of holes 121 and may not be machined as part of the pump 124. The holes 121 enable a fluid, such as the formation fluid 102, to exit the discharge 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 the electrical connections between the power cable 126 and the motor 118 to occur in an environment absent of the formation fluid 102. Further, the motor head 123 extends into the shroud 125 such that holes 121 of the motor head 123, the motor 118, the ESP seal 119, and the holes 121 of the discharge 176 are encapsulated by the shroud 125. The shroud 125 is formed in a cylindrical-like shape around the aforementioned encapsulated elements of the inverted ESP string 112. The shroud 125 encapsulates and isolates these elements from an external environment and contains a flow of the formation fluids 102 coming from the production tubing 117. The shroud 125 may be made out of any durable material known in the art, such as steel.

[0034] The power cable 126 is connected to a portion of the motor head 123 that is located in the external environment outside of the shroud 125 and up hole from the packer 142. Thus, the power cable 126 to motor head 123 connection may be performed in an environment with no formation fluid 102.

[0035] In accordance with one or more embodiments, the formation fluid 102 enters the well 116 through perforations 106 in the casing 108. The formation fluid 102 travels up hole using the production tubing 117. Then, the formation fluid 102 enters the pump 124, powered by the motor 118. Here, the pump 124 pumps the formation fluid 102 into the shroud 125 through the holes 121 of the discharge 176. Subsequently, the formation fluid 102 bypasses the ESP seal 119 and the motor 118, while inside of the shroud 125, and enters the motor head 123 through the holes 121 of the motor head 123. Finally, the formation fluid 102 travels from the motor head 123 back into the production tubing 117 where the pump pressure provided by the pump 124 pushes the formation fluids 102 to the surface location 114.

[0036] In ESP systems 100, conventional procedures require the use of a plug to be run in the hole to set a packer 142. The plug inside of the production tubing 117 may be used to create a barrier to allow the application of differential pressure required to set the packer 142. Once the packer 142 is set, the plug must be retrieved resulting in high costs and long times.

[0037] ESP systems 100 have applications in different oilfield operations and are desired for their high-volume flow rates and pressure boosting capabilities. One application may be during installation of a rigless pumping system, for example when attempting to lift formation fluid 102 to the surface location 114 from a loaded well 116. In some instances, while the pump 124 is connected with the packer 142, it may be desired to change the packer 142/pump 124 setting depth, perhaps to optimize the liquid-lifting process. To accomplish this, a first operation is run to retrieve the entire pumping system to the surface. Next, an additional operation is necessary to unset the packer 142 and deploy it to the new setting depth. A further operation is required to reinstall the pumping system back into the well 116 to latch into the packer 142 at the new setting depth. The above process increases the total time and costs required to complete the operations and to bring production online. As such, embodiments disclosed in Figures 3-9 present systems and methods of setting and unsetting a resettable packer system 144 for pumping operations that include a sliding inner sleeve 146, a fixed outer sleeve 148, and an inflatable packer 150. The resettable packer system 144 may be set and unset a number of times in a single operation without the need of retrieving the entire pumping system, minimizing the time and associated costs of pumping operations.

[0038] Figure 3 shows a cross-sectional view of a resettable packer system 144 in accordance with one or more embodiments of the present disclosure. Here, the resettable packer system 144 includes an inflatable 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 an ESP system 100 within a well 116. The resettable packer system 144 may be flanged or threaded directly to the to the downhole end of the ESP system 100. The inflatable packer 150 may be formed of an elastomeric or flexible material suited for expanding and contracting, such as Kevlar, polymers, polyesters, nanocellulose, or natural materials such as cotton, wool, silk, or linen. Accordingly, the inflatable packer 150 is configured to create a seal in the well 116 by expanding from the resettable packer system 144 to a tubing 117 wall or a casing 108 wall. For example, the inflatable packer 150 may be configured to create a seal in the well 116 by expanding from a first size, at which the inflatable packer 150 does not contact the tubing 117 wall or the casing 108 wall, to a second size, at which the inflatable packer 150 contacts the tubing 117 wall or a casing 108 wall . The pump 124, disposed at an upper end of the resettable packer system 144, is configured to inflate the inflatable packer 150 at a desired depth in the well 116 when activated. Located below the pump 124 are the outer sleeve 148 and inner sleeve 146 of the resettable packer system 144. Both the outer sleeve 148 and inner sleeve 146 are tubular shaped and formed of a durable material, such as steel. The outer sleeve 148 is rigidly fixed to a wedge 154 and a base 156 of the resettable packer system 144 by threaded connections while the inner sleeve 146 is connected to a spring 152 and may slide axially along an inner surface 158 of the outer sleeve 148. Further, the inflatable packer 150 may be bonded to the outer sleeve 148 during the manufacturing process of the resettable packer system 144.

[0039] The spring 152 is disposed within a cavity between the inner sleeve 146 and outer sleeve 148. In addition, the spring 152 may be formed of high-carbon, alloy, or stainless steel and is a compression spring 152. The cavity in which the spring 152 is located is isolated from formation fluid 102 by rubber or elastomer seals 160 above and below the spring 152. The stiffness and contraction length of the spring 152 are selected to match a required spring force needed to move the inner sleeve 146 based on the final desired setting depth and the formation fluid 102 properties. The wedge 154, located at the upper end of resettable the packer system 144, limits the axial upward movement of the inner sleeve 146, whereas 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 base 156 may also be formed of a durable material, such as steel.

[0040] Further, the outer sleeve 148 and inner sleeve 146 both include ports 162. These ports 162 are slots disposed within the outer sleeve 148 and inner sleeve 146 and are configured for the formation fluid 102 to pass through. When the ports 162 of the outer sleeve 148 and the inner sleeve 146 are aligned, formation fluid 102 may travel between the inflatable packer 150 and a bore 164 of the resettable packer system 144. However, when the ports 162 are misaligned, fluid communication between the bore 164 and the inflatable packer 150 is lost as a sealed fluid chamber 166 is formed between an outer surface of the outer sleeve 148 and an interior of the inflatable packer 150. Seals 160 are utilized to prevent formation fluid 102 from passing through the gap between the outer sleeve 148 and inner sleeve 146 when the ports 162 of the outer sleeve 148 and inner sleeve 146 are misaligned. In addition, a rubber or elastomer material O-ring 168 is disposed between the base 156 and the outer sleeve 148 in order to prevent formation fluid 102 from entering into or exiting out of 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 conduit for introducing formation fluid 102 into the inflatable packer 150 and is typically connected to a pressure supply source which may be, for example, a discharge 176. Thus, the packer system 144 is connected to the pump by the control line 170, which supplies pressurized fluid to the packer 150. The control line 170 and the inflatable packer 150 are connected by the check valve 172. The check valve 172 is configured to control a flow 178 of the formation fluid 102 in a single direction. With respect to the discharge 176 and the inflatable packer 150, the check valve 172 controls the direction of the flow 178 (e.g., shown in Figures 4C-4F) of the formation fluid 102 such that the formation fluid 102 only flows from the discharge 176 to the inflatable packer 150. Further, a pressure relief valve 174 disposed along the inflatable packer 150 may be employed to eject formation fluid 102 from the fluid chamber 166 should the pressure within the inflatable packer 150 exceed a pressure threshold. The pressure threshold is determined by an operator of the well 116 according to the design limits of the inflatable packer 150 or to a manufacturer’s suggestion. In addition, the pressure relief valve 174 may be located along an upper surface or downhole surface of the inflatable packer 150 so that the formation fluid 102 may escape into the production tubing 117 or casing 108.

[0042] Figures 4A-4G depict the operational sequence of the resettable packer system

144 in accordance with one or more embodiments. Specifically, Figure 4A depicts the system 144 at the surface location 114 and before the installation of the system 144 within the well 116. Before being lowered downhole, the spring 152 presses a top surface 180 of the inner sleeve 146 against a portion of the wedge 154 which protrudes inwardly, towards the bore 164 of the resettable packer system 144. At this initial position, the ports 162 of the outer sleeve 148 and the inner sleeve 146 are misaligned.

[0043] As the resettable packer system 144 is lowered into the well 116 prior to reaching a desired setting depth, the top surface 180 of the inner sleeve 146, which is exposed to formation fluid 102, experiences a hydrostatic pressure that increases with depth. This hydrostatic pressure pushes downward on the inner sleeve 146 and thereby compressing the spring 152 more than at the surface location 114. An upward force of the spring 152 on the inner sleeve 146 is balanced by a downward force that is a sum of a net hydrostatic force on the inner sleeve 146, a frictional resistance force of the seals 160 against the inner surface 158 of the outer sleeve 148, and a net weight of the inner sleeve 146.

[0044] In Figure 4B, the system 144 is located at the final setting depth. Here, the hydrostatic pressure (Pdepth, no-flow), is higher than at the surface location 114. Therefore, the inner sleeve 146 is pushed downhole such that a bottom surface of the inner sleeve 146 rests against the base 156. In this position, the ports 162 of the outer sleeve 148 and 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 inflatable packer 150. Consequently, formation fluid 102 begins to fill the fluid chamber 166.

[0045] At a desired final setting depth of the resettable packer system 144, the hydrostatic pressure (Pdepth,no-fiow) is highest when there is no flow 178, and thus the compression of the spring 152 is also the greatest at this point. When the pump 124 is activated, a majority of the formation fluid 102 flows upwards through the bore 164 of the resettable packer system 144 towards the ESP system 100 due to a high suction pressure created by the pump 124. Now, a new pressure (Pdepth,flow) which acts on the top surface 180 of the inner sleeve 146 at the setting depth, becomes less than (Pdepth, no- fiow). This in turn yields a force imbalance and causing the spring 152 to push the inner sleeve 146 upwards, thereby misaligning the ports 162 of the outer sleeve 148 and the inner sleeve 146, as seen in Figure 4C. In this position, the formation fluid 102 within the inflatable packer 150 is sealed off from the formation fluid 102 disposed in the well 116 and the bore 164 of the resettable packer system 144.

[0046] The control line 170 of the resettable packer system 144 is connected to the discharge 176. In Figure 4D, the pump 124 has developed pressure which exceeds the pressure within the fluid chamber 166. Consequently, the high-pressure formation fluid 102 passing from the pump 124 to the discharge 176 is introduced into the fluid chamber 166 through the checkvalve 172. Therefore, the inflatable packer 150 is forced to expand until it makes contact with a solid surface, such as the tubing 117 wall or the casing 108 wall. The inflatable packer 150 then provides isolation between the high- pressure formation fluid 102 above the inflatable packer 150 and lower-pressure formation fluid 102 below the inflatable packer 150.

[0047] The pressure threshold of the inflatable packer 150 is determined prior to installation of the resettable packer system 144 based on a required sealing force. The required sealing force is a function of a total weight of the ESP system 100, a contact surface area of the inflatable packer 150 with the tubing 117 wall or casing 108 wall, and additional specifications familiar to a person skilled in the art. In addition, the pump 124 is sized to ensure it can at a minimum, supply a required pressure in the fluid chamber 166. If for any reason the pressure within the fluid chamber 166 exceeds the pressure threshold, the pressure relief valve 174 will open to bleed off excess formation fluid 102 into the well 116, thereby reducing the pressure inside the fluid chamber 166 to the design limits.

[0048] Figure 4E depicts the system 144 if the desired setting depth needs to be changed. Here, the pump 124 is turned off, which immediately causes the direction of the flow 178 to change. At this instant, the ports 162 of the outer sleeve 148 and the inner sleeve 146 are still misaligned, causing high-pressure formation fluid 102 to still be trapped within the fluid chamber 166.

[0049] With the pump 124 deactivated, a static pressure at the top surface 180 of the inner sleeve 146 will begin to increase towards (Pdepth, no-flow), similar to the scenario seen in Figure 4B. The force associated with (Pdepth, no-flow) will push downward on the inner sleeve 146 against the spring force, causing the ports 162 of the outer sleeve 148 and inner sleeve 146 to align with one another. In turn, fluid communication between the fluid chamber 166 and the bore 164 is re-established. Consequently, the high- pressure formation fluid 102 that was sealed within the fluid chamber 166 is released into the bore 164, thereby causing the inflatable packer 150 to contract and break contact with the tubing 117 wall or casing 108 wall, as seen in Figure 4F.

[0050] Subsequent to the inflatable packer 150 contracting, the resettable packer system 144 may be removed from the well 116 or lifted up or down to a new desired setting depth. In order to re-set the inflatable packer 150, the steps described in Figures 4A-4D are repeated. After completion of the entire pumping operation, the steps described in Figure 4E and Figure 4F may be performed, and the entire system 144 may be retrieved to the surface location 114. Further, at the surface location 114, the positions of the outer sleeve 148 and inner sleeve 146 are shown in Figure 4G, which is the same as the positions of the outer sleeve 148 and inner sleeve 146 in Figure 4A.

[0051] Figure 5 shows another embodiment of a resettable packer system 144 in accordance with one or more embodiments of the present disclosure. Components shown in Figure 5 that have been described in Figures 3 and 4 have not been redescribed for purposes of readability and have the same description and purpose as outlined above. However, in this embodiment, a drag force created by the flow 178 of the formation fluid 102 is utilized to slide the inner sleeve 146 of the resettable packer system 144.

[0052] Here, the top surface 180 of the inner sleeve 146, disposed between the outer sleeve 148 and the wedge 154, is sealed off from the formation fluid 102 by seals 160. In addition, the downhole end of the inner sleeve 146 includes a weighted section 181 exposed to the formation fluid 102. The weighted section 181 of the inner sleeve 146 protrudes from the inner sleeve 146 towards the bore 164 of the resettable packer system 144. Further, the weighted section 181 may be formed of a similar material as the inner sleeve 146 or of a denser or heavier material.

[0053] Similar to the embodiment described in Figures 3-4G, in this embodiment, the inner sleeve 146 rests on the upper surface of the base 156 when the ports 162 of the inner sleeve 146 and the ports 162 of the outer sleeve 148 are aligned, thereby permitting fluid communication between the bore 164 and 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 section 181. That is, a total downward force due to the combined weight of the inner sleeve 146 and the weighted section 181 (including frictional resistance of the seals 160 against the inner surface 158 of the outer sleeve 148) is greater than a net hydrostatic force acting upwards on the downhole surface of the inner sleeve 146.

[0054] Figures 6A-6F depict the operational sequence of the system in accordance with one or more embodiments. Specifically, Figure 6A depicts the resettable packer system 144 at the final setting depth within the well 116. In addition, the layout depicted in Figure 6A is the same layout of the resettable packer system 144 at the surface location 114 prior to and during installation of the resettable packer system 144 within the well 116. Furthermore, Figure 6A depicts the resettable packer system 144 before the pump 124 is turned on.

[0055] In Figure 6B, upon activation of the pump 124, formation fluid 102 flows through the bore 164 of the resettable packer system 144 towards the pump 124 due to the suction force created by the pump 124. Consequently, the hydrostatic pressure upstream of the weighted section 181 is greater than the hydrostatic pressure downstream of the weighted section 181. The cross-sectional area of the combination of the weighted section 181 and the portion of the inner sleeve 146 in contact with the weighted section 181 is substantially greater than the cross-sectional area of the inner sleeve 146 just after the weighted section 181. These differences in hydrostatic pressures and cross-sectional areas create a net upward force, or drag, on the inner sleeve 146. In turn, this drag lifts and slides the inner sleeve 146 upwards within the resettable packer system 144, thereby misaligning the ports 162 of the inner sleeve 146 and the ports 162 of the outer sleeve 148. Subsequently, all flow 178 of the formation fluid 102 travels through the bore 164 of the resettable packer system 144, and the formation fluid 102 disposed within the fluid chamber 166 is now trapped. If more flow 178 is drawn in by the pump 124, the drag force increases, resulting in the inner sleeve 146 to be pushed further upwards towards the wedge 154.

[0056] Similar to the process described in Figure 4D, in Figure 6C, the inflatable packer

150 is forced to expand until it makes contact with a solid surface, such as the tubing 117 wall or the casing 108 wall. As a result, the inflatable packer 150 provides isolation between the high-pressure formation fluid 102 above the inflatable packer 150 and lower-pressure formation fluid 102 below the inflatable packer 150. Should the pressure within the fluid chamber 166 exceed the pressure threshold, the pressure relief valve 174 opens to bleed-off excess formation fluid 102 into the well 116 and reduce the pressure within the fluid chamber 166 to the required design limits.

[0057] If the setting depth of the resettable packer system 144 within the well 116 needs to be altered, first, the pump 124 is turned off, and the upward flow 178 of the formation fluid 102 is stopped. This is depicted in Figure 6D. At this instant, the ports 162 of the inner sleeve 146 and the ports 162 of the outer sleeve 148 are still misaligned. In addition, there is still high-pressure formation fluid 102 trapped within the fluid chamber 166 of the resettable packer system 144. Subsequent to the pump 124 being turned off, the upward drag force decreases to zero. In turn, the combined weight of the inner sleeve 146 and the weighted section 181 cause the inner sleeve 146 to slide downwards within the resettable packer system 144. Accordingly, the inner sleeve 146 continues to slide downwards until the downhole end of the inner sleeve 146 rests against the base 156 of the resettable packer system 144, as depicted in Figure 6E. In this position, the ports 162 of the inner sleeve 146 and the ports 162 of the outer sleeve 148 align with one another. Consequently, fluid communication between the fluid chamber 166 and the bore 164 is re-established. Thereby, the high-pressure formation fluid 102 previously disposed within the fluid chamber 166 is released into the bore 164, causing the inflatable packer 150 to contract and break contact with the casing 108 wall or tubing 117 wall.

[0058] In Figure 6F, the fluid chamber 166 has been depressurized to downhole ambient pressures (similar to Figure 6A). The entire bottom hole assembly may be lifted up or down to the newly desired setting depth and the steps depicted by Figures 6B and 6C may be repeated to reset the resettable packer system 144. When the entire pumping operation has been completed, the steps depicted by Figures 6D and 6E may be performed again, and the entire system 144 may be retrieved to the surface location 114. The positions of the inner sleeve 146 and outer sleeve 148 at the surface location 114 are shown in Figure 6F, which are the same as in Figure 6A. [0059] Since the embodiment depicted by Figures 5-6F relies on gravity to ensure the inner sleeve 146 slides downhole to align the ports 162 of the inner sleeve 146 with the ports 162 of the outer sleeve 148, the applicability of this particular embodiment may be constrained to vertical wells 116 or wells 116 with a deviation no more than 30 to 45 degrees from vertical. In order to ensure the inner sleeve 146 is capable of sliding within the resettable packer system 144 in wells 116 with a deviation greater than 30 to 45 degrees from vertical, an additional embodiment of the resettable packer system 144, as depicted in Figure 7, may be employed. In this particular embodiment, a spring 152 located within a sealed cavity between the wedge 154 and the outer sleeve 148 is utilized to ensure that, irrespective of well 116 deviation, once the drag force is removed, the inner sleeve 146 may still slide within the resettable packer system 144. Accordingly, the spring 152 is attached to the top surface 180 of the inner sleeve 146. The spring force of the spring 152 pushes the inner sleeve 146 downhole to make contact with the base 156 of the resettable packer system 144, thereby ensuring that even in very deviated wells, the ports 162 may align and the fluid chamber 166 may be adequately depressurized to facilitate resetting the system 144.

[0060] Figure 8 shows another embodiment of a resettable packer system 144. 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 low carbon steel or an aluminum alloy and each include 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 while the plunger of each piston 182 may be attached to the top surface 180 or 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 inner sleeve 146.

[0061] In the embodiment depicted in Figure 8, the plurality of pistons 182 are double acting pistons, which when actuated, force the plungers to retract within the cylindrical bodies or eject from the cylindrical bodies outwardly. In other embodiments of the resettable packer system 144, another form of piston 182 may be utilized, such as a single acting piston, which when actuated, move in one direction. Further, the plurality of pistons 182 may be actuated hydraulically via the 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 of the plurality of pistons 182 similarly either travels within or away from the cylindrical bodies of the plurality of pistons 182, thereby moving the attached inner sleeve 146 such that the ports 162 of the inner sleeve 146 align or misalign with the ports 162 of the outer sleeve 148.

[0062] Figure 9 depicts a flowchart showing a method for setting and unsetting a resettable packer system 144. While the various flowchart blocks in Figure 9 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively.

[0063] In block 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 first occurs as a hydrostatic force pushes downward on the inner sleeve 146 as the resettable packer system 144 is lowered within the well 116 to a desired depth. Once the resettable packer system 144 reaches the desired depth, the force on the inner sleeve 146 has slid the inner sleeve 146 to a position such that the ports 162 of the inner sleeve 146 and the ports 162 of the outer sleeve 148 are aligned. In turn, the bore 164 of the resettable packer system 144 and the interior of the inflatable packer 150 are in fluid communication. Formation fluid 102 disposed within the bore 164 may flow into the fluid chamber 166 with the inner sleeve 146 in this position.

[0064] In block 202, at the desired depth, the pump 124 of the resettable packer system 144 is activated electrically by operators of the well 116 at the surface location 114. Subsequently, a majority of the formation fluid 102 flows upwards through the bore 164 of the resettable packer system 144 towards the ESP system 100 due to a high suction pressure created by the pump 124. In addition, the inner sleeve 146 slides upwards, 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 upwards through the bore 164.

[0065] In block 203, the formation fluid 102 is pumped into the sealed fluid chamber

166 by the pump 124. The formation fluid 102 traveling upwards through the bore 164 passes through the pump 124 to the discharge 176. The discharge 176 is connected to the inflatable packer 150 by the control line 170. When the pump 124 has developed pressure greater than the pressure within the fluid chamber 166 of the inflatable packer 150, high-pressure formation fluid 102 passing from the pump 124 to the discharge 176 is introduced into the fluid chamber 166 through the control line 170. The formation fluid 102 passes through a check valve 172 upon exiting the control line 170 and prior to entering the fluid chamber 166. The check valve 172 ensures that the formation fluid 102 only travels in the direction from the discharge 176 to the inflatable packer 150. Further, the inflatable packer 150 begins to expand as the formation fluid 102 is pumped into the fluid chamber 166.

[0066] In block 204, when the inflatable packer 150 is fully inflated, the inflatable packer 150 seals the well 116 between the resettable packer system 144 and a tubing 117 wall or a casing 108 wall. The inflatable packer 150 then provides isolation between high-pressure formation fluid 102 above the inflatable packer 150 and lower pressure formation fluid 102 below the inflatable packer 150.

[0067] In block 205, a pumping operation may be performed in the well 116. With the inflatable 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. Consequently, the formation fluid 102 being pumped by the pump 124 from below the inflatable packer 150 is now discharged into the production tubing 117 above the inflatable packer 150 by the discharge 176. Subsequently, this formation fluid 102 travels to the surface location 114 to be produced.

[0068] In block 206, the pump 124 is deactivated electrically by operators 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 operations are complete and the resettable packer system 144 needs to be removed from the well 116. Subsequent to the pump 124 being turned off, the direction of the flow 178 of the formation fluid 102 changes. In addition, the pressure upon the inner sleeve 146 increases, causing the inner sleeve 146 to slide downwards, thereby aligning the ports 162 of the outer sleeve 148 and inner sleeve 146. Accordingly, fluid communication between the bore 164 and the fluid chamber 166 is re-established and the high-pressure formation fluid 102 disposed within the fluid chamber 166 exits into the bore 164, flowing back downhole. As the formation fluid 102 exits the fluid chamber 166, the inflatable packer 150 contracts, thereby breaking contact with the tubing 117 wall or casing 108 wall. The resettable packer system 144 may then be removed from the well 116 or lifted up or down to a new desired setting depth.

[0069] Accordingly, the aforementioned embodiments as disclosed relate to systems and methods useful for minimizing the time and associated costs of pumping operations. The aforementioned embodiments may be set and unset a number of times in a single operation without the need of retrieving the entire pumping system. The disclosed systems and methods of setting and unsetting a resettable packer system 144 for pumping operations advantageously facilitates faster activation and deactivation of a packer 150, which reduces the time to deploy a bottomhole assembly to different required depths. Further, the disclosed systems and methods advantageously cater for large varying flow rates (with ESP systems 100) to lift formation fluid 102 from a well 116.

[0070] Although only a few embodiments of the invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.