Isolating a wellbore with a wellbore isolation system

A system and a method for isolating pressure in a wellbore are described. The system includes a body, a first packer, a second packer, and a control assembly. The body couples to a wellhead and casing. The first packer is disposed within the body and fluidically seals the wellbore providing a first sealing boundary. The second packer is disposed within the body above the first packer to fluidically seal the first packer from the atmosphere providing a second sealing boundary. The first packer and the second packer are spatially arranged within the body to define a packer cavity. The control assembly senses a wellbore pressure on a bottom surface of the first packer, senses a packer cavity pressure, and compares the wellbore pressure to the packer cavity pressure to determine that the wellbore is fluidically sealed from the packer cavity.

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.

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. 1shows a wellbore pressure isolation system100installed in a wellhead102. The wellhead102is coupled to a wellbore104. The wellhead102seals the wellbore104providing a pressure boundary to the environment preventing wellbore104fluids from leaking onto the surface110of the Earth. The wellbore104extends from a surface110of the Earth. The wellbore104includes a casing106with a flange108. The flange108is flush with or above the surface110of the Earth. The wellbore pressure isolation system100is mechanically coupled to the casing106flange108. For example, the wellhead102can be mechanically coupled by fastening devices128. For example, fastening devices128can be bolts and nuts or studs and nuts.

The wellhead102can include a spool112. The spool112has a body122with flanges124coupled to both ends of the body. The body122is a cylindrical hollow body. The flanges124have voids126configured to accommodate fastening devices128. The body122can include one or more outlets114. The spool112couples the casing106to the wellhead102. The spool112can be used to couple a tubing hanger to the wellhead102. The spool112is mechanically coupled to the casing106or tubing hanger. For example, the spool112can be welded or engaged with a slip and seal assembly to the casing106or tubing hanger. The spool112is mechanically coupled to other components in the wellhead by fastening devices128disposed in the voids126of the flanges124. The spool112can be mechanically coupled to another spool112or a blowout preventer116. For example, the spool112can be fastened to another spool with fastening devices128such as bolts and nuts or studs and nuts. The outlet114can connect the hollow cylinder body122to a valve116. The valve116can open and close to allow wellbore fluid to flow through the outlet114. The valve116can be connected to a choke and kill conduit to control well pressure excursions. Alternatively, the valve116can be connected to drilling mud system during drilling operations.

The spool112can be constructed from a metal such as steel or an alloy. The spool112has a nominal outer diameter that can be between 6 inches and 20 inches. The dimensions and material properties of the spool112can conform to an American Petroleum Institute (API) standard or a proprietary specification.

The wellhead102can include a blowout preventer116configured to rapidly seal the wellhead102in an emergency such as a blowout. A blowout is an uncontrolled release of wellbore fluids and gases. The wellhead102can include multiple blowout preventers116. A blowout preventer116can be an annular blowout preventer116aor a ram blowout preventer116b.

The annual blowout preventer116aseals around a tubular118disposed in the wellhead102. The ram blowout preventer116bcan shear the tubular118disposed in the wellhead102. A blowout preventer116can require preventative or corrective maintenance tasks. The maintenance tasks can require blowout preventer116removal. With the blowout preventer116removed or unable to operatively seal the wellbore, no means of preventing a blowout is provided by the wellhead102.

The wellhead102includes the wellbore pressure isolation system100mechanically coupled between the spool112and the blowout preventer116. The wellbore pressure isolation system100includes a body130. The body130includes an upper section132, coupled to a middle section134, and a lower section136coupled to the middle section134. The body130is a single, unitary body with three sections. Alternatively, the body130can have three separate sections coupled to each other.

The upper section132is configured to accept the blowout preventer116. The upper section132is a cylindrical hollow body. The upper section132has flanges138coupled to both ends of the upper section132. The flanges138have voids126configured to accommodate fastening devices128. The blowout preventer116has a corresponding flange192and voids194configured to accommodate fastening devices128. The fastening devices128pass through the voids126and the voids194to secure the upper section132flanges138to the blowout preventer116flanges. The upper section132can include a pressure sensor configured to sense atmospheric pressure. The upper section132can be constructed from a metal. For example, the upper section132can be constructed from steel or an alloy.

The middle section134is mechanically coupled to the upper section132and the lower section136. The middle section134is a hollow body with an inner surface162. The middle section134has flanges150coupled to both ends of the hollow body. The flanges150have voids152configured to accommodate fastening devices128to couple to the middle section134to the upper section132and the lower section136. For example, the fastening devices128can be bolts with nuts or studs with nuts. The middle section134can be constructed from a metal. For example, the middle section134can be constructed from steel or an alloy.

The middle section134is configured to accommodate a first packer140in a first location142and a second packer144at a second location146. The first packer140is positioned below the second packer144. Below the second packer144is toward the wellbore104. The first packer140is configured to fluidically seal the wellbore104providing a first sealing boundary defined by the bottom surface154of the first packer140and the casing inner surface156. The second packer144is configured to fluidically seal the first packer140from an atmosphere158of the Earth providing a second sealing boundary defined by the bottom160of the second packer144and the middle body134inner surface162. 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 cavity164is defined by the bottom surface160of the second packer144, the middle section134inner surface, and a top surface162of the first packer140. The pressure cavity164is bounded by the first sealing boundary and the second sealing boundary. The pressure cavity164isolates the wellbore104from the atmosphere158. The pressure cavity164allows for the monitoring of the first sealing boundary and the second sealing boundary integrity.

The middle section134has an inner profile148. The inner profile148is key-like shaped to allow the first packer140to pass through the second location142and seat at the first location142. The inner profile148is key-like shaped to seat the second packer144at the second location142.

The middle section134can include multiple ports180configured to accept lockdown devices182. The threaded ports180are situated about the first packer140and second packer144to allow the lockdown devices182mechanically couple to the first packer140and second packer144. The lockdown devices182secure the first packer140at the first location142and second packer144at the second location146. The lockdown devices182can be lockdown screws. The threaded ports180can be threaded to accept the lockdown screws. The wellhead102can include a hydraulic control system184to operate the lockdown screws. Operating the lockdown screws includes rotating the lockdown screws to engage to or disengage from the first packer140and the second packer144. Alternatively, the lockdown device can be movable rings.

The middle section134hollow body is configured to accept multiple sensors. The sensors include a first pressure sensor166and a second pressure sensor168. The first pressure sensor166is senses the wellbore pressure. The wellbore pressure is sensed in cavity170defined by the bottom154of the first packer140, the lower body inner surface172, and the casing inner surface156. The first pressure sensor166transmit signals representing the wellbore pressure to a controller174. The second pressure sensor168senses a second pressure in the packer cavity164and transmit signals representing the second pressure to the control assembly174. The middle section can include an atmospheric pressure sensor configured to sense atmospheric pressure158and transmit signals representing the atmospheric pressure to the controller.

The sensors can include a first location sensor176and a second location sensor178. The first location sensor176and a second location sensor178can be a position switch or a proximity sensor. Alternatively, Radio Frequency Identification (RFID) tags can be placed in the first packer140and the second packer144. The first location sensor176and a second location sensor178confirm that the first packer140and the second packer144have landed at the first location142and the second location146that is required to assure seal integrity and proper activation to lock the first packer140and the second packer144in place. The first location sensor176and the second location sensor178can be a RFID tag reader. The first location sensor176is disposed within the middle section134at the first location142to sense the first packer140when the first packer140is seated at the first location142. The first location sensor176can be coupled to the first packer140. The second location sensor178is disposed within the middle section134at the second location146to sense the second packer144when the second packer144is seated at the second location146. The second location sensor178can be coupled to the second packer146. The first location sensor176and the second location sensor178transmit signals representing the sensed first packer location and the second packer location to the control assembly174.

The control assembly174is coupled to the sensors disposed in the middle section134. The control assembly174receives the signal representing the sensed wellbore cavity170pressure from the first pressure sensor166and the signal representing the sensed packer cavity164pressure from the second pressure sensor168. The control assembly174compares the wellbore cavity170pressure to the packer cavity164pressure to determine whether the first packer140and the second packer144are fluidically sealing the wellbore cavity170from the packer cavity164. The control assembly174receives the signal representing the atmospheric158pressure. The control assembly174compares the packer cavity164pressure to the atmosphere158pressure to determine whether the second packer144is fluidically sealing the packer cavity164from the atmosphere158. Also, the control assembly174receives the signal representing the sensed first packer140location when the first packer140is seated at the first location142and the signal representing the sensed second packer144location when the second packer144is seated at the second location146to determine whether the first packer140and the second packer144are placed in the correct locations to fluidically seal the wellbore cavity170from the packer cavity164and the packer cavity164from the atmosphere158. When the first packer140and the second packer144are fluidically sealing the wellbore cavity170, the wellhead102components, for example a blowout preventer116, can be removed from the wellhead102to perform maintenance. When the first packer140and the second packer144are not fluidically sealing the wellbore cavity170, maintenance cannot safely be performed on the wellhead102components.

The control assembly174can 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 controller174can 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 cavity170pressure to the packer cavity164pressure to determine that the first packer140and the second packer144are fluidically sealing the wellbore cavity170from the packer cavity164and the packer cavity164from the atmosphere158. Also, the one or more computer processors determine when the first packer140is seated at the first location142and when the second packer144is seated at the second location146to determine that the first packer140and the second packer144are placed in the correct locations to fluidically seal the wellbore cavity170from the packer cavity164.

The lower section136is 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 spool112. The lower section136is configured to accept the casing106flange108or the spool112. The lower section136is also configured to couple to the middle section134. The lower section136is a cylindrical hollow body. The lower section136has flanges138coupled to both ends of the upper section132. The flanges138have voids126configured to accommodate fastening devices128. The lower section136can be constructed from a metal. For example, the lower section136can be constructed from steel or an alloy.

The first packer140and the second packer144are configured to seat in the first location142and the second location146, respectively. The first packer140has an outer profile176corresponding to the first location142inner profile148of the middle section134. The first packer140fluidically seals wellbore104in the middle section134providing the first pressure boundary for the wellbore104. The second packer144has an outer profile178corresponding to the second location146of the inner profile148of the middle section134. The second packer144fluidically seals the first packer140from the atmosphere158. The top surface196of the second packer144can be exposed to the atmosphere158when the wellhead102components, for example the blowout preventer116is removed. The inner profile148is key-shaped to allow the first packer140to pass through the second location142and seat at the first location142. For example, the first location142inner profile148can have a 1/16″ smaller diameter than the second location146inner profile148. The first packer140can have a 1/16″ smaller diameter, corresponding to the first location142inner profile148diameter. The first packer140can pass through the second location146, but seats at the first location142. The second packer144has a 1/16″ larger diameter than the first packer140seats at the second location146. The first packer140and the second packer144can each have an o-ring rubber seal188around their circumference providing a sealing surface the inner profile148.

The first packer140and the second packer144are 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 connector190mechanically couples the first packer140to the second packer144. The mechanical connector190can 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 connector190can be a box connection, where the threads are internal to the box. The mechanical connector190can have an outer diameter corresponding to a standard API connection size. For example, the mechanical connector190can 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 packer140and the second packer144are configured to accept multiple lockdown devices182. The lockdown devices182secure the first packer140at the first location142and the second packer144at the second location146in the middle section134.

The second packer can be offset from the first packer by a packer spacer housing186. The packer spacer housing186is a cylindrical body. The packer spacer housing186can be hollow. The packer spacer housing is mechanically coupled to the first packer140and the second packer144. For example, the packer spacer housing can be welded or fastened to the first packer140and the second packer144.

Referring toFIG. 2, a wellhead sealing assembly200can isolate the wellbore104at the wellhead102during drilling operations. A first packer240and a second packer244are coupled to a drill string202to isolate the wellbore104at the wellhead102during drilling operations. The drill string200can include an upper drill pipe204and a lower drill pipe206. The upper drill pipe's204and the lower drill pipe's206dimensions 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 housing286. The control assembly274is disposed in the packer spacer housing286. The control assembly274is substantially similar to the control assembly described earlier.

The first packer240and the second packer244are substantially similar to the first packer140and the second packer140discussed earlier, with the below exceptions. The first pressure sensor266is disposed in the first packer240. The first pressure sensor266senses the wellbore pressure on the bottom surface254of the first packer240when the wellhead sealing assembly200is disposed in the wellhead102. The second pressure sensor268is disposed in the second packer244. The second pressure sensor268senses the packer cavity pressure on the bottom surface260of the second packer240when the wellhead sealing assembly200is disposed in the wellhead102. The first pressure sensor266transmits signals representing the wellbore pressure to a controller274. The second pressure sensor168senses a second pressure in the packer cavity264and transmit signals representing the second pressure to the control assembly274. The first location sensor276is disposed within the first packer240to sense that the first packer240is seated in the wellhead102. The second location sensor278is disposed within the second packer244to sense that the second packer244is seated in the wellhead102. The first location sensor276and the second location sensor278transmit signals representing the sensed first packer location and the second packer location to the control assembly274.

Referring toFIGS. 3A and 3B, a wellhead sealing assembly300can isolate the wellbore104at the wellhead during production operations. A J-slot running tool302can be coupled to the second packer344, as shown inFIG. 3B, to place the wellhead sealing assembly300in the wellhead. The J-slot running tool302is a common J shaped profile tool used to place downhole tools and assemblies in tubulars. Referring toFIG. 3A, the J-slot running tool302includes an inner mandrel304with a setting pin306. The inner mandrel304is optionally coupled to the drill string308or a workover tubular. Axial and rotational movement to place the J-slot running tool302in the wellbore104is controlled by a drilling rig (not shown). The J-slot running tool302includes an outer sleeve310with a J-shaped void312extending from a top surface314of the outer sleeve310. The J-shaped void is configured to accept the setting pin306and optionally lock the inner mandrel304to the outer sleeve310. The outer sleeve310is coupled to the downhole tool to be placed in the wellbore104. In this implementation, the downhole tool is the wellhead sealing assembly300. The wellhead sealing assembly300includes a second packer344coupled to the outer sleeve302of J-slot running tool302. A packer spacer housing386is coupled to the second packer334by a first mechanical connector316to space the second pacer344from the first packer340. The first packer340is coupled to the packer spacer housing386by a second mechanical connector318. The first mechanical connector316and the second mechanical connector318are substantially similar to the mechanical connectors discussed earlier.

FIG. 4is a flow chart of an example method400of isolating a wellbore with a wellbore isolation system according to the implementations of the present disclosure. At402, 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. At404, a signal representing the wellbore pressure is transmitted to a controller. At406, 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. At408, a signal representing the second pressure is transmitted to the controller. At410, the wellbore pressure is compared to the second pressure. At412, 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