Patent Publication Number: US-11396789-B2

Title: Isolating a wellbore with a wellbore isolation system

Description:
TECHNICAL FIELD 
     This disclosure relates to sealing pressurized fluid and gas in a wellbore. 
     BACKGROUND 
     Wellbores in an oil and gas well are filled with both liquid and gaseous phases of various fluids and chemicals including water, oils, and hydrocarbon gases. The fluids and gasses in the wellbore can be pressurized. A wellhead is installed on the wellbore to seal the wellbore and to control the flow of oil and gas from the wellbore. The wellhead can include multiple components including isolation valves, blowout preventers, chokes, and spools. The wellhead is mechanically coupled to a wellbore casing disposed in the wellbore. Maintenance tasks may be performed on the components of the wellhead. The components of the wellhead may require removal to perform the preventative or corrective maintenance tasks. The wellbore may need to be isolated during the performance of the wellhead maintenance. 
     SUMMARY 
     This disclosure describes technologies related to isolating a wellbore with a wellbore isolation system. Implementations of the present disclosure include a wellbore pressure isolation system. The wellbore pressure isolation system includes a body, a first packer, a second packer, and a control assembly. The body couples to a wellbore casing assembly at a wellhead. The first packer is coupled to the body. The first packer is configured to be disposed inside the wellhead. The first packer fluidically seals the wellbore providing a first sealing boundary. The first sealing boundary prevents a pressurized fluid from crossing from a first side of the first sealing boundary to a second side of the first sealing boundary. The second packer is coupled to the body. The second packer is configured to be disposed in the wellhead at an uphole location relative to the first packer. The second packer fluidically seals the first packer from an atmosphere of the Earth providing a second sealing boundary. The second sealing boundary prevents a second pressurized fluid from crossing from a first side of the second sealing boundary to a second side of the second sealing boundary. The first packer and the second packer are spatially arranged within the body to define a packer cavity. The control assembly is coupled to the body, the first packer, and the second packer. The control assembly senses a wellbore pressure on a bottom surface of the first packer, senses a second pressure in the packer cavity, and compares the wellbore pressure to the second pressure to determine that the wellbore is fluidically sealed from the packer cavity. 
     In some implementations, the body further includes an upper section, a middle section, and a lower section. The upper section is configured to accept a blowout preventer assembly. The middle section is coupled to the upper section. The middle section is configured to accommodate the first packer and the second packer. The first packer is positioned below the second packer. Below the second packer is toward the wellbore. The lower section is coupled to the middle section. The lower section is configured to couple to a wellbore casing at a surface of the Earth. 
     In some implementations, the first packer and the second packer are configured to receive a locking device from the middle section of the body. The locking device is configured to secure the first packer and the second packer to the body. 
     In some implementations, the locking device is multiple lockdown screws. 
     In some implementations, the wellbore pressure isolation system further includes a packer spacer housing configured to mechanically couple the first packer to the second packer. The second packer is offset from the first packer. 
     In some implementations, the control assembly further includes a controller, a first pressure sensor, and a second pressure sensor. The first pressure sensor is configured to sense the wellbore pressure on the bottom surface of the first packer and transmit signals representing the wellbore pressure to the controller. The second pressure sensor is configured to sense the second pressure in the packer cavity and transmit signals representing the second pressure to the controller. The controller compares the wellbore pressure to the second pressure to determine that the wellbore is fluidically sealed from the packer cavity. 
     In some implementations, the middle section further includes a first location sensor and a second location sensor. The first location sensor is disposed within the body and coupled to the first packer. The first location sensor is configured to sense the first packer location. The second location sensor is disposed within the body and coupled to the second packer. The second location sensor is configured to sense the second packer location. The first location sensor and the second location sensor are configured to sense the first packer location and the second packer location and transmit signals representing the sensed first packer location and the second packer location to the control assembly. The control assembly receives the signal representing the sensed first packer location and the signal representing the sensed second packer location to determine that the first packer and the second packer are placed to fluidically seal the wellbore from the packer cavity. 
     In some implementations, the first packer and the second packer are coupled to a drill string and configured to isolate the wellbore during drilling operations. 
     In some implementations, the first packer and the second packer are disposed in the wellbore with a J-slot running tool configured to couple with the first packer and the second packer to place the first packer and the second packer in the body. 
     Further implementations of the present disclosure include a wellhead sealing assembly. The wellhead sealing assembly includes a first packer, a second packer, a packer spacer housing, and a control assembly. The first packer is configured to be disposed in a wellhead. The first packer fluidically seals a wellbore providing a first sealing boundary. The first sealing boundary is configured to prevent a pressurized fluid from crossing from a first side of the first sealing boundary to a second side of the first sealing boundary. The second packer is configured to be disposed in a wellhead. The second packer fluidically seals the first packer from an atmosphere of the Earth providing a second sealing boundary. The second sealing boundary is configured to prevent a second pressurized fluid from crossing from a first side of the second sealing boundary to a second side of the second sealing boundary. The packer spacer housing is configured to mechanically couple the first packer to the second packer. The second packer is offset from the first packer. The control assembly is coupled to the first packer and the second packer. The control assembly is configured to sense a wellbore pressure on a bottom surface of the first packer, sense a second pressure in a packer cavity defined by the first packer, the second packer, the packer spacer housing, and the wellhead, and compare the wellbore pressure to the second pressure to determine that the wellbore is fluidically sealed from the packer cavity. 
     In some implementations, the wellhead sealing assembly further includes a first pressure sensor and a second pressure sensor. The first pressure sensor is disposed in the first packer. The first pressure sensor is configured to sense a first pressure on a bottom surface of the first packer and transmit signals representing the first pressure to the control assembly. The bottom surface of the first packer is a wellbore pressure. The second pressure sensor is disposed in the second packer. The second pressure sensor is configured to sense a second pressure in a packer cavity defined by a top surface of the first packer, a bottom surface of the second packer, the packer spacer housing, and the wellhead, and transmit signals representing the second pressure to the control assembly. 
     In some implementations, the control assembly further includes a controller. The controller is configured to receive signals representing the first pressure, receive signals representing the second pressure, and compare the first pressure to the second pressure to determine that the wellbore is fluidically sealed from the packer cavity. 
     In some implementations, the controller is further configured to receive a signal from a first location sensor disposed in the first packer. The first location sensor is configured to sense the first packer location. The controller is further configured to receive a signal from a second location sensor disposed in the second packer. The second location sensor is configured to sense the second packer location. The controller is further configured to determine that the first packer and the second packer are placed to fluidically seal the wellbore from the packer cavity. 
     In some implementations, the first packer and the second packer are configured to receive a locking device from the wellhead, wherein the locking device is configured to secure the first packer and the second packer to the wellhead. 
     Further implementations of the present disclosure include a method for isolating a wellbore pressure at the wellhead. The method includes sensing a wellbore pressure on a bottom surface of a first packer. The first packer is disposed in a wellhead and configured to provide a first sealing boundary to seal the wellbore. The first sealing boundary is configured to prevent a pressurized fluid from crossing from a first side of the first sealing boundary to a second side of the first sealing boundary. The method includes transmitting a signal representing the wellbore pressure to a controller. The method includes sensing a second pressure in a packer cavity. The packer cavity is defined by a top surface of the first packer, a bottom surface of a second packer disposed in the wellhead and configured provide a second sealing boundary to seal the wellhead. The second sealing boundary is configured to prevent a second pressurized fluid from crossing from a first side of the second sealing boundary to a second side of the second sealing boundary. The method includes transmitting a signal representing the second pressure to the controller. The method includes comparing the wellbore pressure to the second pressure. The method includes determining that the wellbore is fluidically sealed from the packer cavity. 
     In some implementations, the method further includes sensing a third pressure on a top surface of the second packer, transmitting a signal representing the third pressure to the controller, comparing the second pressure to the third pressure, and determining that the packer cavity is fluidically sealed from the top surface of the second packer. 
     In some implementations, the third pressure is an atmospheric pressure of the Earth. 
     In some implementations, the wellbore is sealed from packer cavity when the second pressure is less than the wellbore pressure. 
     In some implementations, the wellbore is sealed from the packer cavity when a difference between the wellbore pressure and the second pressure is greater than or equal to a target pressure difference. 
     In some implementations, the method further includes monitoring the wellbore pressure and the second pressure for a time period and determining that the wellbore is fluidically sealed from the packer cavity when the difference between the wellbore pressure and the second pressure is greater than or equal to the target pressure difference for the time period. 
     In some implementations, the method further includes sensing a first packer seated condition. The first packer seated condition occurs when the first packer is engaged in a first location configured to seal the wellbore. The method further includes transmitting a signal representing the first packer seated condition to the controller. The method further includes sensing a second packer seated condition. The second packer seated condition occurs when the second packer is engaged to a second location configured to seal the first packer from an atmosphere of the Earth. The method further includes transmitting a signal representing the second packer seated condition to the controller. The method further includes determining that the first packer and the second packer are positioned to fluidically seal the wellbore when the first packer seated condition and the second packer seated condition is received by the controller. 
     In some implementations, the method further includes, responsive to determining that the first packer and the second packer are positioned to fluidically seal the wellbore by the first packer seated condition and the second packer seated condition, sensing a first packer locked condition. The first packer locked condition occurs when the first packer is locked in the first location by a lockdown device. The method further includes transmitting a signal representing the first packer locked condition to the controller. The method further includes sensing a second packer locked condition. The second packer locked condition occurs when the second packer is locked in the second location by a lockdown device. The method further includes transmitting a signal representing the second packer locked condition to the controller. The method further includes determining that the first packer is locked in the first location and the second packer is locked in the second location to fluidically seal the wellbore when the first packer locked condition and the second packer locked condition is received by the controller. 
     The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic view of a wellhead pressure isolation system installed on a wellbore. 
         FIG. 2  is a schematic view of wellhead pressure isolation system of  FIG. 1  installed on a drill pipe. 
         FIG. 3A  is a schematic view of a J-slot running tool. 
         FIG. 3B  is a schematic view of isolation packers of  FIG. 1  installed J-slot running tool. 
         FIG. 4  is a flow chart of an example method of isolating a wellbore using a wellhead pressure isolation system according to the implementations of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure describes a system and a method for isolating a wellbore with a wellbore pressure isolation system. The wellbore in an oil and gas well is filled with both pressurized liquid and gaseous phases of various fluids including water, oils, and hydrocarbon gases. A wellhead is installed on the surface of the Earth and coupled to the wellbore to seal the wellbore and to control the flow of oil and gas from the wellbore. The wellhead is mechanically coupled to a wellbore casing disposed in the wellbore. The wellhead can include multiple components to seal and control the wellbore fluids and gasses including isolation valves, blowout preventers, chokes, and spools. Maintenance tasks may be performed on the components of the wellhead. The maintenance tasks can be preventative or corrective. The components of the wellhead may require removal to perform the preventative or corrective maintenance tasks. Some of the components, when removed, will prevent the wellhead from isolating the wellbore. In some cases, uncontrolled formation pressure surges or fluid flows can travel through the wellbore to the surface of the Earth. This can cause severe environmental damage and endanger personnel. The wellbore may need to be isolated during the performance of the wellhead maintenance to prevent these detrimental effects. 
     Implementations of the present disclosure realize one or more of the following advantages. Preventative and corrective maintenance on wellhead components can be conducted. For example, a blowout preventer or wellhead isolation valve can be removed and replaced. Additionally, environmental safety is improved. For example, pressure boundaries are provided to prevent the uncontrolled release of wellbore fluids and gases into the area surrounding a wellbore. The surrounding area could be the surface of the Earth if the wellhead is installed on land or the ocean if the wellhead is a subsea wellhead. Also, personnel safety is improved. Additional pressure boundaries are can be used during wellbore operations. Ease of compliance with regulatory restrictions is improved as wellhead maintenance can be more safely conducted with additional barriers. 
       FIG. 1  shows a wellbore pressure isolation system  100  installed in a wellhead  102 . The wellhead  102  is coupled to a wellbore  104 . The wellhead  102  seals the wellbore  104  providing a pressure boundary to the environment preventing wellbore  104  fluids from leaking onto the surface  110  of the Earth. The wellbore  104  extends from a surface  110  of the Earth. The wellbore  104  includes a casing  106  with a flange  108 . The flange  108  is flush with or above the surface  110  of the Earth. The wellbore pressure isolation system  100  is mechanically coupled to the casing  106  flange  108 . For example, the wellhead  102  can be mechanically coupled by fastening devices  128 . For example, fastening devices  128  can be bolts and nuts or studs and nuts. 
     The wellhead  102  can include a spool  112 . The spool  112  has a body  122  with flanges  124  coupled to both ends of the body. The body  122  is a cylindrical hollow body. The flanges  124  have voids  126  configured to accommodate fastening devices  128 . The body  122  can include one or more outlets  114 . The spool  112  couples the casing  106  to the wellhead  102 . The spool  112  can be used to couple a tubing hanger to the wellhead  102 . The spool  112  is mechanically coupled to the casing  106  or tubing hanger. For example, the spool  112  can be welded or engaged with a slip and seal assembly to the casing  106  or tubing hanger. The spool  112  is mechanically coupled to other components in the wellhead by fastening devices  128  disposed in the voids  126  of the flanges  124 . The spool  112  can be mechanically coupled to another spool  112  or a blowout preventer  116 . For example, the spool  112  can be fastened to another spool with fastening devices  128  such as bolts and nuts or studs and nuts. The outlet  114  can connect the hollow cylinder body  122  to a valve  116 . The valve  116  can open and close to allow wellbore fluid to flow through the outlet  114 . The valve  116  can be connected to a choke and kill conduit to control well pressure excursions. Alternatively, the valve  116  can be connected to drilling mud system during drilling operations. 
     The spool  112  can be constructed from a metal such as steel or an alloy. The spool  112  has a nominal outer diameter that can be between 6 inches and 20 inches. The dimensions and material properties of the spool  112  can conform to an American Petroleum Institute (API) standard or a proprietary specification. 
     The wellhead  102  can include a blowout preventer  116  configured to rapidly seal the wellhead  102  in an emergency such as a blowout. A blowout is an uncontrolled release of wellbore fluids and gases. The wellhead  102  can include multiple blowout preventers  116 . A blowout preventer  116  can be an annular blowout preventer  116   a  or a ram blowout preventer  116   b.    
     The annual blowout preventer  116   a  seals around a tubular  118  disposed in the wellhead  102 . The ram blowout preventer  116   b  can shear the tubular  118  disposed in the wellhead  102 . A blowout preventer  116  can require preventative or corrective maintenance tasks. The maintenance tasks can require blowout preventer  116  removal. With the blowout preventer  116  removed or unable to operatively seal the wellbore, no means of preventing a blowout is provided by the wellhead  102 . 
     The wellhead  102  includes the wellbore pressure isolation system  100  mechanically coupled between the spool  112  and the blowout preventer  116 . The wellbore pressure isolation system  100  includes a body  130 . The body  130  includes an upper section  132 , coupled to a middle section  134 , and a lower section  136  coupled to the middle section  134 . The body  130  is a single, unitary body with three sections. Alternatively, the body  130  can have three separate sections coupled to each other. 
     The upper section  132  is configured to accept the blowout preventer  116 . The upper section  132  is a cylindrical hollow body. The upper section  132  has flanges  138  coupled to both ends of the upper section  132 . The flanges  138  have voids  126  configured to accommodate fastening devices  128 . The blowout preventer  116  has a corresponding flange  192  and voids  194  configured to accommodate fastening devices  128 . The fastening devices  128  pass through the voids  126  and the voids  194  to secure the upper section  132  flanges  138  to the blowout preventer  116  flanges. The upper section  132  can include a pressure sensor configured to sense atmospheric pressure. The upper section  132  can be constructed from a metal. For example, the upper section  132  can be constructed from steel or an alloy. 
     The middle section  134  is mechanically coupled to the upper section  132  and the lower section  136 . The middle section  134  is a hollow body with an inner surface  162 . The middle section  134  has flanges  150  coupled to both ends of the hollow body. The flanges  150  have voids  152  configured to accommodate fastening devices  128  to couple to the middle section  134  to the upper section  132  and the lower section  136 . For example, the fastening devices  128  can be bolts with nuts or studs with nuts. The middle section  134  can be constructed from a metal. For example, the middle section  134  can be constructed from steel or an alloy. 
     The middle section  134  is configured to accommodate a first packer  140  in a first location  142  and a second packer  144  at a second location  146 . The first packer  140  is positioned below the second packer  144 . Below the second packer  144  is toward the wellbore  104 . The first packer  140  is configured to fluidically seal the wellbore  104  providing a first sealing boundary defined by the bottom surface  154  of the first packer  140  and the casing inner surface  156 . The second packer  144  is configured to fluidically seal the first packer  140  from an atmosphere  158  of the Earth providing a second sealing boundary defined by the bottom  160  of the second packer  144  and the middle body  134  inner surface  162 . The sealing boundary prevents a pressurized fluid from crossing from one side of the sealing boundary to another side of the sealing boundary. The sealing boundary does not appreciably deflect when pressurized from one side or both sides. A pressure cavity  164  is defined by the bottom surface  160  of the second packer  144 , the middle section  134  inner surface, and a top surface  162  of the first packer  140 . The pressure cavity  164  is bounded by the first sealing boundary and the second sealing boundary. The pressure cavity  164  isolates the wellbore  104  from the atmosphere  158 . The pressure cavity  164  allows for the monitoring of the first sealing boundary and the second sealing boundary integrity. 
     The middle section  134  has an inner profile  148 . The inner profile  148  is key-like shaped to allow the first packer  140  to pass through the second location  142  and seat at the first location  142 . The inner profile  148  is key-like shaped to seat the second packer  144  at the second location  142 . 
     The middle section  134  can include multiple ports  180  configured to accept lockdown devices  182 . The threaded ports  180  are situated about the first packer  140  and second packer  144  to allow the lockdown devices  182  mechanically couple to the first packer  140  and second packer  144 . The lockdown devices  182  secure the first packer  140  at the first location  142  and second packer  144  at the second location  146 . The lockdown devices  182  can be lockdown screws. The threaded ports  180  can be threaded to accept the lockdown screws. The wellhead  102  can include a hydraulic control system  184  to operate the lockdown screws. Operating the lockdown screws includes rotating the lockdown screws to engage to or disengage from the first packer  140  and the second packer  144 . Alternatively, the lockdown device can be movable rings. 
     The middle section  134  hollow body is configured to accept multiple sensors. The sensors include a first pressure sensor  166  and a second pressure sensor  168 . The first pressure sensor  166  is senses the wellbore pressure. The wellbore pressure is sensed in cavity  170  defined by the bottom  154  of the first packer  140 , the lower body inner surface  172 , and the casing inner surface  156 . The first pressure sensor  166  transmit signals representing the wellbore pressure to a controller  174 . The second pressure sensor  168  senses a second pressure in the packer cavity  164  and transmit signals representing the second pressure to the control assembly  174 . The middle section can include an atmospheric pressure sensor configured to sense atmospheric pressure  158  and transmit signals representing the atmospheric pressure to the controller. 
     The sensors can include a first location sensor  176  and a second location sensor  178 . The first location sensor  176  and a second location sensor  178  can be a position switch or a proximity sensor. Alternatively, Radio Frequency Identification (RFID) tags can be placed in the first packer  140  and the second packer  144 . The first location sensor  176  and a second location sensor  178  confirm that the first packer  140  and the second packer  144  have landed at the first location  142  and the second location  146  that is required to assure seal integrity and proper activation to lock the first packer  140  and the second packer  144  in place. The first location sensor  176  and the second location sensor  178  can be a RFID tag reader. The first location sensor  176  is disposed within the middle section  134  at the first location  142  to sense the first packer  140  when the first packer  140  is seated at the first location  142 . The first location sensor  176  can be coupled to the first packer  140 . The second location sensor  178  is disposed within the middle section  134  at the second location  146  to sense the second packer  144  when the second packer  144  is seated at the second location  146 . The second location sensor  178  can be coupled to the second packer  146 . The first location sensor  176  and the second location sensor  178  transmit signals representing the sensed first packer location and the second packer location to the control assembly  174 . 
     The control assembly  174  is coupled to the sensors disposed in the middle section  134 . The control assembly  174  receives the signal representing the sensed wellbore cavity  170  pressure from the first pressure sensor  166  and the signal representing the sensed packer cavity  164  pressure from the second pressure sensor  168 . The control assembly  174  compares the wellbore cavity  170  pressure to the packer cavity  164  pressure to determine whether the first packer  140  and the second packer  144  are fluidically sealing the wellbore cavity  170  from the packer cavity  164 . The control assembly  174  receives the signal representing the atmospheric  158  pressure. The control assembly  174  compares the packer cavity  164  pressure to the atmosphere  158  pressure to determine whether the second packer  144  is fluidically sealing the packer cavity  164  from the atmosphere  158 . Also, the control assembly  174  receives the signal representing the sensed first packer  140  location when the first packer  140  is seated at the first location  142  and the signal representing the sensed second packer  144  location when the second packer  144  is seated at the second location  146  to determine whether the first packer  140  and the second packer  144  are placed in the correct locations to fluidically seal the wellbore cavity  170  from the packer cavity  164  and the packer cavity  164  from the atmosphere  158 . When the first packer  140  and the second packer  144  are fluidically sealing the wellbore cavity  170 , the wellhead  102  components, for example a blowout preventer  116 , can be removed from the wellhead  102  to perform maintenance. When the first packer  140  and the second packer  144  are not fluidically sealing the wellbore cavity  170 , maintenance cannot safely be performed on the wellhead  102  components. 
     The control assembly  174  can include a controller. The controller can be a non-transitory computer-readable medium storing instructions executable by one or more processors to perform operations described here. The controller  174  can include firmware, software, hardware or combinations of them. The instructions, when executed by the one or more computer processors, cause the one or more computer processors to compare the wellbore cavity  170  pressure to the packer cavity  164  pressure to determine that the first packer  140  and the second packer  144  are fluidically sealing the wellbore cavity  170  from the packer cavity  164  and the packer cavity  164  from the atmosphere  158 . Also, the one or more computer processors determine when the first packer  140  is seated at the first location  142  and when the second packer  144  is seated at the second location  146  to determine that the first packer  140  and the second packer  144  are placed in the correct locations to fluidically seal the wellbore cavity  170  from the packer cavity  164 . 
     The lower section  136  is coupled to the middle section, the lower section configured to couple to a wellbore casing at a surface of the Earth. The lower section can be a spool  112 . The lower section  136  is configured to accept the casing  106  flange  108  or the spool  112 . The lower section  136  is also configured to couple to the middle section  134 . The lower section  136  is a cylindrical hollow body. The lower section  136  has flanges  138  coupled to both ends of the upper section  132 . The flanges  138  have voids  126  configured to accommodate fastening devices  128 . The lower section  136  can be constructed from a metal. For example, the lower section  136  can be constructed from steel or an alloy. 
     The first packer  140  and the second packer  144  are configured to seat in the first location  142  and the second location  146 , respectively. The first packer  140  has an outer profile  176  corresponding to the first location  142  inner profile  148  of the middle section  134 . The first packer  140  fluidically seals wellbore  104  in the middle section  134  providing the first pressure boundary for the wellbore  104 . The second packer  144  has an outer profile  178  corresponding to the second location  146  of the inner profile  148  of the middle section  134 . The second packer  144  fluidically seals the first packer  140  from the atmosphere  158 . The top surface  196  of the second packer  144  can be exposed to the atmosphere  158  when the wellhead  102  components, for example the blowout preventer  116  is removed. The inner profile  148  is key-shaped to allow the first packer  140  to pass through the second location  142  and seat at the first location  142 . For example, the first location  142  inner profile  148  can have a 1/16″ smaller diameter than the second location  146  inner profile  148 . The first packer  140  can have a 1/16″ smaller diameter, corresponding to the first location  142  inner profile  148  diameter. The first packer  140  can pass through the second location  146 , but seats at the first location  142 . The second packer  144  has a 1/16″ larger diameter than the first packer  140  seats at the second location  146 . The first packer  140  and the second packer  144  can each have an o-ring rubber seal  188  around their circumference providing a sealing surface the inner profile  148 . 
     The first packer  140  and the second packer  144  are a typical oil and gas industry rubber elastomer element (the packer) that is designed based on requirement to a pressure rating based on wellbore conditions and regulatory requirements. Different packers can be rated for different pressures. For example, packers can be rated to 1000 psi, 3000 psi, 5000 psi, 10,000 psi, or 24,000 psi. A mechanical connector  190  mechanically couples the first packer  140  to the second packer  144 . The mechanical connector  190  can be a standard API rotary shoulder pin connector. For example, the standard API rotary-shouldered connector can be a regular connection, a numeric connection, an internal flush connection, or a full-hole connection. For example, the pin connection can be a manufacturer proprietary design. Alternatively, the mechanical connector  190  can be a box connection, where the threads are internal to the box. The mechanical connector  190  can have an outer diameter corresponding to a standard API connection size. For example, the mechanical connector  190  can have an outer diameter of 4½ inches, 5½ inches, 6⅝ inches, 7 inches, 7⅝ inches, 8⅝ inches, 9⅝ inches, 10¾ inches, 11¾ inches, or 13⅜ inches. 
     The first packer  140  and the second packer  144  are configured to accept multiple lockdown devices  182 . The lockdown devices  182  secure the first packer  140  at the first location  142  and the second packer  144  at the second location  146  in the middle section  134 . 
     The second packer can be offset from the first packer by a packer spacer housing  186 . The packer spacer housing  186  is a cylindrical body. The packer spacer housing  186  can be hollow. The packer spacer housing is mechanically coupled to the first packer  140  and the second packer  144 . For example, the packer spacer housing can be welded or fastened to the first packer  140  and the second packer  144 . 
     Referring to  FIG. 2 , a wellhead sealing assembly  200  can isolate the wellbore  104  at the wellhead  102  during drilling operations. A first packer  240  and a second packer  244  are coupled to a drill string  202  to isolate the wellbore  104  at the wellhead  102  during drilling operations. The drill string  200  can include an upper drill pipe  204  and a lower drill pipe  206 . The upper drill pipe&#39;s  204  and the lower drill pipe&#39;s  206  dimensions and material properties can conform to an API standard or a proprietary specification. For example, the drill pipe can have an outer diameter of 4½ inches, 5½ inches, 6⅝ inches, 7 inches, 7⅝ inches, 8⅝ inches, 9⅝ inches, 10¾ inches, 11¾ inches, or 13⅜ inches. The second packer can be offset from the first packer by a packer spacer housing  286 . The control assembly  274  is disposed in the packer spacer housing  286 . The control assembly  274  is substantially similar to the control assembly described earlier. 
     The first packer  240  and the second packer  244  are substantially similar to the first packer  140  and the second packer  140  discussed earlier, with the below exceptions. The first pressure sensor  266  is disposed in the first packer  240 . The first pressure sensor  266  senses the wellbore pressure on the bottom surface  254  of the first packer  240  when the wellhead sealing assembly  200  is disposed in the wellhead  102 . The second pressure sensor  268  is disposed in the second packer  244 . The second pressure sensor  268  senses the packer cavity pressure on the bottom surface  260  of the second packer  240  when the wellhead sealing assembly  200  is disposed in the wellhead  102 . The first pressure sensor  266  transmits signals representing the wellbore pressure to a controller  274 . The second pressure sensor  168  senses a second pressure in the packer cavity  264  and transmit signals representing the second pressure to the control assembly  274 . The first location sensor  276  is disposed within the first packer  240  to sense that the first packer  240  is seated in the wellhead  102 . The second location sensor  278  is disposed within the second packer  244  to sense that the second packer  244  is seated in the wellhead  102 . The first location sensor  276  and the second location sensor  278  transmit signals representing the sensed first packer location and the second packer location to the control assembly  274 . 
     Referring to  FIGS. 3A and 3B , a wellhead sealing assembly  300  can isolate the wellbore  104  at the wellhead during production operations. A J-slot running tool  302  can be coupled to the second packer  344 , as shown in  FIG. 3B , to place the wellhead sealing assembly  300  in the wellhead. The J-slot running tool  302  is a common J shaped profile tool used to place downhole tools and assemblies in tubulars. Referring to  FIG. 3A , the J-slot running tool  302  includes an inner mandrel  304  with a setting pin  306 . The inner mandrel  304  is optionally coupled to the drill string  308  or a workover tubular. Axial and rotational movement to place the J-slot running tool  302  in the wellbore  104  is controlled by a drilling rig (not shown). The J-slot running tool  302  includes an outer sleeve  310  with a J-shaped void  312  extending from a top surface  314  of the outer sleeve  310 . The J-shaped void is configured to accept the setting pin  306  and optionally lock the inner mandrel  304  to the outer sleeve  310 . The outer sleeve  310  is coupled to the downhole tool to be placed in the wellbore  104 . In this implementation, the downhole tool is the wellhead sealing assembly  300 . The wellhead sealing assembly  300  includes a second packer  344  coupled to the outer sleeve  302  of J-slot running tool  302 . A packer spacer housing  386  is coupled to the second packer  334  by a first mechanical connector  316  to space the second pacer  344  from the first packer  340 . The first packer  340  is coupled to the packer spacer housing  386  by a second mechanical connector  318 . The first mechanical connector  316  and the second mechanical connector  318  are substantially similar to the mechanical connectors discussed earlier. 
       FIG. 4  is a flow chart of an example method  400  of isolating a wellbore with a wellbore isolation system according to the implementations of the present disclosure. At  402 , a wellbore pressure on a bottom surface of a first packer is sensed. The first packer is disposed in a wellhead and configured to provide a first sealing boundary to seal the wellbore. For example, the first packer providing a first sealing boundary can include a location sensor sensing a first packer seated condition. The first packer seated condition occurs when the first packer is engaged to a first location configured to seal the wellbore. The location sensor can transmit a signal representing the first packer seated condition to the controller. For example, responsive to the controller receiving the first packer seated condition, a first packer locked condition is sensed. The first packer locked condition occurs when the first packer is locked in the first location by a lockdown device. The lockdown device transmits a signal representing the first packer locked condition to the controller. At  404 , a signal representing the wellbore pressure is transmitted to a controller. At  406 , a second pressure in a packer cavity is sensed. The packer cavity is defined by a top surface of the first packer, a bottom surface of a second packer disposed in the wellhead and configured provide a second sealing boundary to seal the wellhead, and the wellhead. For example, the second packer providing a second sealing boundary can include a location sensor sensing a second packer seated condition. The second packer seated condition occurs when the second packer is engaged to a second location configured to seal the first packer from an atmosphere of the Earth. The location sensor can transmit a signal representing the second packer seated condition to the controller. For example, responsive to the controller receiving the second packer seated condition, a second packer locked condition is sensed. The second packer locked condition occurs when the second packer is locked in the second location by the lockdown device. The lockdown device transmits a signal representing the second packer locked condition to the controller. At  408 , a signal representing the second pressure is transmitted to the controller. At  410 , the wellbore pressure is compared to the second pressure. At  412 , it is determined whether the wellbore is fluidically sealed from the packer cavity. For example, the wellbore can sealed from packer cavity when the second pressure is less than the wellbore pressure. For example, the wellbore can be sealed from the packer cavity when a difference between the wellbore pressure and the second pressure is greater than or equal to a target pressure difference. For example, the wellbore pressure and the second pressure can be monitored for a time period. For example, the wellbore can be fluidically sealed from the packer cavity when the difference between the wellbore pressure and the second pressure is greater than or equal to the target pressure difference for the time period. For example, the controller receives the first packer seated condition and the second packer seated condition to determine that the first packer and the second packer are positioned to fluidically seal the wellbore. For example, the controller receives the first packer locked condition and the second packer locked condition to determine that the first packer is locked in the first location and the second packer is locked in the second location to fluidically seal the wellbore. 
     Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations, and alterations to the following details are within the scope and spirit of the disclosure. Accordingly, the example implementations described herein and provided in the appended figures are set forth without any loss of generality, and without imposing limitations on the claimed implementations. 
     Although the present implementations have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents