Technical Field

The present invention relates to monitoring a pressure in an annulus in a well extending through a formation of the Earth.

Background

Oil and gas wells have in general three different purposes; as producers of hydrocarbons, injectors of water or gas for reservoir pressure support or for depositing purposes, or as exploration wells. A well is constructed by drilling a hole into the reservoir using a drilling rig and then inserting sections of steel pipe, casing or liner into the hole to impart structural integrity to the wellbore. Deeper sections of the well are drilled with progressively smaller well diameters, and consequently casings with progressively smaller diameters are used for deeper sections of the well.

The multiple casings are arranged concentrically, and the casings typically extend up to a platform or template. Tubing is inserted into the casing to transport fluid to or from the surface. The interval between the tubing and the smallest-diameter casing (typically the production casing) is referred to as the “A-annulus”, and the interval between the smallest-diameter casing and the next smallest casing is typically referred to as the “B- annulus”. The B-annulus is e.g. the annulus between a production casing and the adjacent larger-diameter casing. Further annuli, e.g. the “C-annulus” and “D-annulus”, are defined between subsequent casings, and the largest-diameter casing and the formation.

The A-annulus is typically accessible from the platform or template, and pressure in the A-annulus is monitored and managed using control systems on the platform or Christmas tree, to avoid failure of tubing, casing or downhole equipment, and maintain safety and integrity of the well. In contrast, at least for a sub-sea well that terminates at a template, the B-annulus and subsequent annuli are typically sealed, and cannot be accessed from the template. Currently, the re-use of production casing in subsea wells having an active A-annulus (e.g. wells with artificial gas lift) may be limited to wells with a working B-annulus monitoring system, e.g. if industry regulations impose such a limit. In this case, wells where this system has failed, or which did not have such a system installed to start with, cannot be directly re-used for e.g. deep side tracks. In such cases, at least a large portion of the production casing (e.g. at least down to the depth at which a side-track will be drilled) typically has to be removed for a pressure monitoring system to be installed, which can add significant delays and costs.

Summary of Invention

It is an object of the present invention to overcome or at least mitigate the problems identified above.

In accordance with a first aspect there is provided a method for monitoring a pressure in an annulus behind a casing, comprising: running into the casing: a tubular, such that the tubular is arranged concentrically within the casing; at least one packer in an undeployed state, wherein the at least one packer is configured to provide, in a deployed state, a sealed volume between the exterior of the tubular and an interior surface of the casing; and a pressure sensor configured to measure the pressure in the annulus. The method further comprises deploying the at least one packer, such that the pressure sensor is located in the sealed volume, wherein the sealed volume is connected to the annulus by a perforation in the casing; and measuring the pressure in the annulus using the pressure sensor.

The casing may be a first casing, and the annulus may be defined between: the first casing and a second casing, wherein the first casing and the second casing are installed in a well extending through a formation of the Earth, and the first casing is arranged concentrically within the second casing; or the casing and the formation.

The method may further comprise creating the perforation in the casing.

The method may further comprise running into the casing a perforation device, wherein the packer is deployed such that the perforation device is also located in the sealed volume; and perforating the casing using the perforation device, to thereby create the perforation in the casing. The perforation device may comprise one or more of a shaped explosive charge configured to be detonated to create the perforation, a drill, a punch, a chemical that is corrosive to the casing, and a laser.

The tubular may be a production tubing joint.

The annulus may be a B-annulus.

The at least one packer may be attached to an exterior portion of the tubular, and the packer, the perforation device and the pressure sensor may be run into the well with the tubular.

The method may comprise, before the step of running into the casing, removing an existing tubular that is arranged concentrically within the casing.

The at least one packer may be a single packer that extends from a first side of the tubular. The tubular may comprise at least one spacer configured to brace the tubular against the casing responsive to the single packer being deployed.

The at least one packer may comprise a first packer and a second packer arranged at a first and a second longitudinal position, respectively, on an exterior portion of the tubular, wherein the pressure sensor is arranged on or adjacent to the exterior portion of the tubular, between the first and second packers, and after the tubular is deployed the perforation in the casing is located longitudinally between the first packer and the second packer, and wherein a conduit extends through the first and second packers. Deploying the at least one packer may comprise deploying the first and second packers to provide the sealed volume between the packers, wherein, after the packers are deployed, the conduit provides fluid communication between the portion of the well above the first packer and the portion of the well below the second packer. The sealed volume between the first and second packers may be a substantially annular volume between the tubular and the casing that is sealed off from the portions of the well above the first packer and below the second packer, and is open to the annulus via the perforation in the casing.

The tubular may be run into the casing as part of a completion process. The conduit may be provided by at least one tube that extends substantially parallel to the tubular and is located radially between the tubular and the casing.

The conduit may be arranged concentrically around the tubular, thereby providing a fluid communication path that is a further annulus between the inner surface of the conduit and the exterior of the tubular.

Electrical power and/or data communication may be provided to the pressure sensor via a cable extending through at least one of the packers, and the cable optionally extends to a lower portion of the well.

The pressure sensor may be configured to communicate wirelessly to a receiver located above the first packer.

The tubular may be production tubing.

There is provided a system for monitoring a pressure in an annulus behind a casing, comprising: a tubular, and, arranged on or adjacent to an exterior portion of the tubular: a pressure sensor configured to measure the pressure in the annulus; and at least one packer, wherein the at least one packer is configured to provide, in a deployed state, a sealed volume between the exterior of the tubular and an interior surface of the casing, such that the the pressure sensor is located in the sealed volume, such that the sealed volume is connected to the annulus by a perforation in the casing.

The at least one packer may be a single packer extending from one side of the tubular.

The system may further comprise at least one spacer configured to brace the tubular against the casing responsive to the single packer being deployed.

The at least one packer may comprise a first packer and a second packer arranged at a first and a second longitudinal position, respectively, on an exterior portion of the tubular. The pressure sensor may be arranged on or adjacent to the exterior portion of the tubular, between the first and second packers; and the system may further comprise a conduit extending through the first and second packers, wherein, in use, the hole in the casing is located longitudinally between the first packer and the second packer, and wherein, once deployed, the first and second packers provide a sealed volume between the packers, and the conduit provides fluid communication between the portion of the well above the first packer and the portion of the well below the second packer.

The system may further comprise a perforation device configured to create the perforation in the casing, wherein the at least one packer is configured such that, after the at least one packer is deployed, the perforation device is also located in the sealed volume.

In accordance with a second aspect there is provided a method for monitoring a pressure in an annulus behind a casing, comprising: creating a hole in the casing, sealing the hole in the casing using a plug, wherein the plug comprises a pressure sensor configured to measure the pressure in the annulus, and an inductive transceiver for wireless electrical power and/or data transfer; and measuring the pressure in the annulus using the pressure sensor.

The casing may be a first casing, and the annulus may be defined between the first casing and a second casing, wherein the first casing and the second casing are installed in a well extending through a formation of the Earth, and the first casing is arranged concentrically within the second casing, or the first casing and the formation.

The hole may be created in the casing using a wireline tool that is run into the well.

The plug may be installed using a wireline tool that is run into the well, optionally the same tool that is used to create the hole.

The method may further comprise: running a tubular into the casing, such that a further inductive transceiver arranged on an exterior portion of the tubular is located near the inductive transceiver of the plug, for electrical power and/or data transfer to and/or from the pressure sensor. There is provided a system for monitoring a pressure in an annulus behind a casing, comprising a plug configured to seal a hole in the casing, wherein the plug comprises a pressure sensor configured to measure the pressure in the annulus, and an inductive transceiver for wireless electrical power and/or data transfer.

In accordance with a third aspect there is provided a method for monitoring a pressure in an annulus behind a retrofit casing arranged concentrically within a well, comprising: cutting through a casing located in the well at a first height, and removing from the well the portion of the casing above the first height; running a new casing into the well, wherein the new casing is substantially the same or similar diameter as the casing, such that the new casing abuts the portion of the casing in the well, wherein the new casing comprises a pressure sensor arranged on an exterior portion of the new casing; forming the retrofit casing by joining the new casing to the portion of the casing in the well, such that a seal is provided between the new casing and the casing; and measuring the pressure in the annulus.

The retrofit casing may be a first casing and the annulus may be defined between the first casing and a second casing, wherein the first casing and the second casing are installed in a well extending through a formation of the Earth, and the first casing is arranged concentrically within the second casing, or the first casing and the formation.

After the new casing has been run into the well, the pressure sensor may be located close to the first height.

The new casing may further comprise an inductive transceiver arranged on the exterior portion of the new casing and coupled to the pressure sensor.

The method may further comprise: running a tubular into the well, such that a further inductive transceiver arranged on an exterior portion of the tubular is located near the inductive transceiver, for electrical power and/or data transfer to and/or from the pressure sensor. The method may further comprise, before cutting through the casing, identifying a top level of sealant in the annulus, wherein the first height is above the top level of the sealant.

There is provided a system for measuring a pressure in an annulus behind a retrofit casing arranged concentrically within a well, comprising: the retrofit casing, wherein the retrofit casing comprises: a portion of a casing located in the well below a first height, the casing having been cut through at a first height and the portion of the casing above the first height having been removed from the well; and a new casing having substantially the same or similar diameter as the casing, wherein the new casing abuts, and is joined to, the portion of the casing in the well, such that a seal is provided between the new casing and the casing, wherein the new casing comprises a pressure sensor arranged on an exterior portion of the new casing.

Embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings, in which:

Brief Description of Drawings

Figure 1 A shows an apparatus for monitoring a pressure in an annulus.

Figure 1 B shows the apparatus of Figure 1A in situ in a well, before perforation of a casing.

Figure 1 C shows the apparatus of Figure 1A in situ in the well, after perforation of the casing.

Figure 2A shows an apparatus for monitoring a pressure in an annulus in a well, e.g. a well that uses artificial gas-lift.

Figure 2B shows an apparatus for monitoring a pressure in an annulus in a well, e.g. a well that uses artificial gas-lift.

Figure 3A shows an apparatus for monitoring a pressure in an annulus, and a tool used for an installation procedure. Figure 3B shows the apparatus of Figure 3A, after the tool has been removed from the well.

Figures 4A to 4D illustrate a process of installing an apparatus for monitoring a pressure in an annulus.

Figure 5 shows a high-level flow diagram.

Figure 6 shows a high-level flow diagram.

Figure 7 shows a high-level flow diagram.

Detailed description

Disclosed herein are solutions allowing pressure surveillance in a closed annulus, without having to fully remove the production casing. The idea is primarily based on B- annulus monitoring, but is also applicable to other uses, such as direct measurement of reservoir pressure (behind casing) and measurement of pressure in other annuli. The solutions provide methods of retrofitting an already completed wellbore to enable annulus monitoring. The method is especially suited for monitoring the B-annulus in a subsea well, in which access to the B-annulus is restricted. Monitoring the pressure in the B-annulus may enable detection of potentially dangerous conditions that could result in damage to the well, casings and/or equipment, and may thereby enable actions to avert such undesirable results.

Here, a tubular is any tubing, casing, liner or pipe that is run into a well.

In the case that the solutions are applied for monitoring a pressure in a B-annulus, the pressure is typically monitored in an upper portion of the B-annulus that is not filled with a solid sealant, e.g. concrete or barite. Instead, the upper portion of the B-annulus is typically filled with liquid, e.g. mud, water and/or oil-based mud.

Figures 1 A to 1C, 2A and 2B illustrate systems and methods in accordance with a first aspect, in which a tubular is run into the casing such that the tubular is arranged concentrically within the casing, and, at least one packer in an undeployed state and a pressure sensor configured to measure the pressure in the annulus are also run into the casing. The at least one packer is configured to provide, in a deployed state, a sealed volume between the exterior of the tubular and an interior surface of the casing. The at least one packer is deployed, such that the pressure sensor is located in the sealed volume, wherein the sealed volume is connected to the annulus by a perforation in the casing, and the pressure in the annulus is measured using the pressure sensor.

Figure 1 A shows a tubular 110 before deployment into a well extending into a formation of the Earth. The tubular is e.g. production tubing or, as in the specific example shown in Figure 1A, a tubing joint that joins adjacent sections of production tubing. A packer 102 is arranged on an exterior portion of the tubular 110, and the packer is in an undeployed state before the tubular is deployed into the well. The packer 102 is e.g. a swell packer, or any other suitable type of packer. The packer 102 is configured to provide a sealed volume between the exterior of the tubular and an adjacent casing, without completely sealing the annulus between the exterior of the tubular and the adjacent casing. In the embodiment shown in Figure 1A, this is achieved using a substantially oval-shaped packer that extends from one side of the tubular 110, such that the perimeter of the packer encloses an empty space 108. A pressure sensor 104 and a perforation device 106 are arranged in the space 108. In an embodiment, the pressure sensor 104 is configured to measure temperature as well as pressure. Alternatively, a separate temperature sensor may be included along with the pressure sensor. A cable 114 for electrical power and/or data transfer extends to the detonator and, in parallel, to the pressure sensor 104.

In the embodiment shown in Figure 1A the perforation device 106 is a shaped explosive charge, and a detonator 112 for detonating the shaped explosive charge is also arranged in the space 108. In an alternative embodiment, the perforation device 106 is one or more of a drill, a punch, a chemical that is corrosive to the casing, and a laser, or any other device that is capable of creating a perforation in the casing. The description below refers to the shaped explosive charge, but it is to be understood that any other suitable perforation device could be used instead. In another alternative embodiment, a perforation is created in the casing before the tubular and pressure sensor are deployed, and no perforation device is arranged in the space 108. The tubular 110 is then run into a well containing a casing 120. The well extends through a formation of the Earth. The casing is e.g. a first casing, and an annulus 140 is defined between the first casing 120 and a second casing 130, where the first casing 120 is arranged concentrically within the second casing 130. Alternatively, the casing 120 is located within the bare well itself, so that the annulus 140 is defined between the casing 120 and the formation 130. In this embodiment, the annulus 140 is the B- annulus. In an alternative embodiment, the annulus is any other suitable annulus defined between two casings or two tubulars, or between a casing or a tubular and the formation. Once the tubular 110 is run into the well, the packer 102 is deployed so that the packer 102 provides a seal between the exterior of the tubular 110 and the casing 120. In particular, a sealed volume 108 is enclosed by the packer 102 between the exterior of the tubular 110 and the casing 120. This arrangement is shown in Figure 1 B. The system includes at least one spacer 113 extending from the tubular 110 and configured to brace the tubular 110 against the casing 120 responsive to the packer being deployed. In particular, the spacer maintains the tubular in a substantially central location within the casing, to thereby prevent damage to the tubular that could result from bending. In the embodiment shown in Figures 1 A and 1 B, the spacer comprises at least one fin. The at least one fin has sufficient mechanical strength to provide the required bracing. In the case that the tubular needs to be removed from the casing at a later stage, the tubular can be pulled and/or twisted, if necessary, to break the fins and release the tubular. In an alternative embodiment the spacer is provided by e.g. an additional packer or any other suitable element.

The shaped explosive charge 106, the detonator 112 (not necessarily included if the perforation device 106 is not a shaped explosive charge) and the pressure sensor 104 are located within the sealed volume 108. It can be ensured that the volume 108 is completely sealed by monitoring the pressure in the sealed volume 108 using the pressure sensor 104. Signals/data from the pressure sensor 104 are transmitted via the cable 114 to a receiver at a remote location, e.g. on a platform or Christmas tree, or an onshore facility. Of course, any suitable alternative method can be used for signal/data transmission, e.g. wireless transmission from the pressure sensor to a receiver located outside the packer.

The shaped explosive charge 108, which can also be referred to as a perforation charge, is directed towards the casing 120. Responsive to a signal transmitted via the cable 114, the detonator 112 issues a detonation signal which causes the shaped explosive charge 108 to detonate. Alternatively, an electrical current is provided to the detonator via the cable, which causes a filament inside the detonator to heat up, which causes the detonator explosive to explode. This explosion is transferred to the shaped charge via contact causing the shaped charge to explode. The resulting explosion perforates the first casing 120 to provide a perforation 122, without damaging the pressure sensor 104, as shown in Figure 1 C. In an alternative embodiment using a different perforation device, the perforation is created using the different perforation device. The perforation 122 provides fluid communication between the sealed volume 108 and the annulus 140, such that the pressure between the sealed volume 108 and the annulus 140 is equalized. The pressure in the annulus 140 is then measured using the pressure sensor 104, and the pressure in the annulus 140 can be monitored over time using the pressure sensor 104.

Figure 2A shows a casing 220 located in a well extending through a formation of the Earth. The well is e.g. a well that uses artificial gas-lift. The casing is e.g. a first casing, and an annulus 240 is defined between the first casing 220 and a second casing (not shown here), where the first casing is arranged concentrically within the second casing. Alternatively, the annulus 240 is defined between the casing 220 and the formation. In this embodiment, the annulus 240 is the B-annulus. In an alternative embodiment, the annulus is any other suitable annulus defined between two casings or two tubulars, or between a casing or a tubular and the formation. A hole 222, i.e. a perforation, has been created in the first casing, providing fluid communication between the interior volume of the first casing and the annulus 240. The perforation 222 is created in an earlier step of the method, e.g. using a wireline tool, before any of the other components shown in Figure 2A have been run into the well. Alternatively, the perforation 222 is created after the components Figure 2A have been run into the well, using a perforation device such as the perforation device 106 shown in Figures 1A and 1 B.

A tubular 210 is run into the well. The tubular is e.g. production tubing run into the well as part of a completion process. A first packer 212 in an undeployed state is arranged at a first longitudinal position on an exterior portion of the tubular, and a second packer 214 in an undeployed state is arranged at a second longitudinal position on the exterior portion of the tubular. A pressure sensor 216 is arranged on or adjacent to the exterior portion of the tubular, between the first 212 and second 214 packers, and a conduit 270 extends through the first and second packers. It is not necessary for the pressure sensor 216 to be fixed to the exterior portion of the tubular. In an embodiment, the pressure sensor 216 is configured to measure temperature as well as pressure. Alternatively, a separate temperature sensor may be included along with the pressure sensor. After the tubular 210 is run into the well, the hole in the casing is located longitudinally between the first packer and the second packer. Alternatively, if the perforation may not yet have been created, in which case the tubular and packers are run into the casing to a desired position (with no perforation yet in the casing). In the embodiment shown in Figure 2A (and, correspondingly, the embodiment shown in Figure 2B), a cable 218 for electrical power and/or data transfer extends along the tubular and is connected to the pressure sensor 216. In this embodiment, the cable 218 extends deeper into the well to provide data and/or power transfer facilities to sensors or other equipment deeper in the well. In an alternative embodiment, the cable 218 terminates at the pressure sensor 216 and does not extend deeper into the well. Alternatively, the pressure sensor 216 is in wireless communication, e.g. inductive communication, with a receiver (not shown here) that is located above the first packer 212 and has a wired connection to a remote location.

To reach the configuration shown in Figure 2A, the first packer 212 and the second packer 214 are deployed to provide a seal between the exterior of the tubular 210 and the interior surface of the first casing 220. Once the packers are deployed, the internal volume defined by the two packers, the exterior of the tubular and the interior of the first casing is open to the annulus 240 (via the hole 222), but is sealed off from the volume within the first casing above the first packer and below the second packer. Alternatively, a perforation device (e.g. the perforation device 106 shown in Figures 1A and 1 B) is located between the two packers, and is used to create the perforation either before or after the packers are deployed. The pressure sensor 216 is then used to measure the pressure in the annulus. The conduit 270 provides a bypass through the sealed volume between the two packers, and provides fluid communication between the annular volume within the first casing and above the first packer, and the annular volume within the first casing and below the second packer. This bypass provided by the conduit 270 is essential in a well that uses artificial gas-lift, in which gas is typically injected down the A-annulus. In the embodiment shown in Figure 2A, the conduit is a tube that is located between the tubular 210 and the first casing 220, on one side of the well. In an alternative embodiment, multiple tubes 270 (not shown here) are used to bypass the sealed volume.

Figure 2B shows an alternative embodiment in which a conduit 280 is arranged concentrically around the tubular, and the fluid communication path is therefore an annulus between the inner surface of the conduit 280 and the exterior of tubular 210. The other elements of the embodiment of Figure 2B are the same as the embodiment of Figure 2A. In the embodiment of Figure 2B, the pressure sensor 216 is fixed on, or is adjacent to, the exterior of the conduit 280, and the packers 212,214 extend from the exterior surface of the conduit. As shown in an end-on, cross-sectional view included in Figure 2B, the conduit 280 is coupled to the tubular 210 via support members 282.

Figures 3A and 3B illustrate a system and method in accordance with a second aspect, in which a hole is created in a casing, the hole in the casing is sealed using a plug, wherein the plug comprises a pressure sensor configured to measure the pressure in the annulus, and an inductive transceiver for wireless electrical power and/or data transfer, the pressure in the annulus is measured using the pressure sensor.

Figure 3A shows a casing 320 located in a well extending through a formation in the Earth. The casing is e.g. a first casing, and an annulus 340 (shown in Figure 3B) is defined between the first casing 320 and a second casing 330, where the first casing 320 is arranged concentrically within the second casing 330. Alternatively, the annulus 340 is defined between the casing 320 and the formation 330. In this embodiment, the annulus 340 is the B-annulus. In an alternative embodiment, the annulus is any other suitable annulus defined between two casings or two tubulars, or between a casing or a tubular and the formation.

A tool 370 is run into the casing and is used to create a hole 322 in the casing. The tool 370 is e.g. a wireline tool. In the embodiment shown in Figure 3A, the tool also carries a plug 350. In an alternative embodiment, a different tool is run into the casing 320 and is used to create the hole 322 and is then removed from the well, before the tool 370 is run into the casing carrying the plug 350. The tool is then used to install the plug 350 in the hole 322 in the casing 320. The plug seals the hole 322. In this embodiment, a sealing wedge 352 is used to expand the plug to seal the hole 322. Of course, any suitable mechanism or method can be used to ensure that the plug 350 seals the hole 322.

The plug 350 includes a pressure sensor 354, and an inductive transceiver 356 that is operationally in communication with the pressure sensor to provide electrical power to the sensor, and to receive measurement data from the pressure sensor. In an embodiment, the inductive transceiver is also configured to transmit control signals and/or data to the pressure sensor. In the configuration shown in Figure 3A, the pressure sensor is able to measure the pressure in the annulus 340. The plug optionally includes a data storage unit to store pressure measurement data generated by the pressure sensor 354. In an embodiment, the pressure sensor 354 is configured to measure temperature as well as pressure. Alternatively, a separate temperature sensor may be included along with the pressure sensor.

The tool 370 is then removed from the well, and a tubular 360 is run into the well, such that the tubular 360 is arranged concentrically within the casing 320. The tubular 360 is e.g. production tubing that is run into the well as part of a completion process. A further inductive transceiver 364 is arranged on an exterior portion of the tubular 360, and a cable 362 is connected to the further inductive transceiver 364. With the tubular 360 in place in the well, the further inductive transceiver is located near the inductive transceiver 356 of the plug, and electrical power is provided to the pressure sensor 354 via the cable 362 and inductive power transfer between the further inductive transceiver 364 and the inductive transceiver 356 in the plug. Further, pressure measurement data is transferred from the pressure sensor, or from the data storage unit if present, via the inductive transceiver 356 in the plug, the further inductive transceiver 364 and the cable 362, to a remote location for processing. The remote location is e.g. on a platform, a template or an onshore facility.

Figures 4A to 4D illustrate a system and a method in accordance with a third aspect, in which a casing located in the well is cut through at a first height, and the portion of the casing above the first height is removed from the well. A new casing is then run into the well, wherein the new casing is substantially the same or similar diameter as the casing, such that the new casing abuts the portion of the casing in the well, wherein the new casing comprises a pressure sensor arranged on an exterior portion of the new casing. A retrofit casing is then formed by joining the new casing to the portion of the casing in the well, such that a seal is provided between the new casing and the casing; and the pressure in an annulus behind the retrofit casing is then measured.

Figure 4A shows a casing 420. The casing is e.g. a first casing that is located concentrically within a second casing 430, or within the formation 430. An annulus 440 is defined between the first casing 420 and the second casing 430, or alternatively between the casing 420 and the formation 430. The annulus is e.g. the B-annulus. The annulus 440 is filled to a first height with a solid sealant 490, e.g. cement, or drilling fluid solids (e.g. barite), or the collapsed formation. The first casing 420 is e.g. a 9%”, a 9%” or a 107” casing. The second casing 430 is e.g. a 13%”, 13%” or 14” casing.

Figure 4B illustrates an initial step of installing an apparatus for measuring a pressure in the annulus 440. The top of the cement or barite is detected, using e.g. a wireline tool. Then, the casing 420 is cut through at a second height 420a that is just above the first height, and the portion of the casing 420 above the second height 420a is removed from the well.

Figure 4C illustrates a subsequent step of the installation process. A new casing 425 is run into the well, where the new casing 425 has substantially the same, or similar, diameter as the casing 420. The new casing 425 is e.g. a 9%”, a 97s” or a 107” casing. The new casing 425 is run into the well until the lower end of the new casing abuts and lines up with the upper end of the casing. A sensor unit 426 is arranged on the exterior of the new casing 425, preferably close to the lower end of the new casing. The sensor unit 426 includes a pressure sensor, and an inductive transceiver coupled to the pressure sensor. In an embodiment, the sensor unit also includes a depth correlation device. In an embodiment, the pressure sensor is configured to measure temperature as well as pressure. Alternatively, the sensor unit includes a separate temperature sensor. The inductive transceiver is for receiving inductive power and transferring to the sensor, and for transmitting pressure measurement data from the pressure sensor. The new casing 425 is joined to the casing using joining features 419, providing a seal between the new casing and the casing. The joining features are e.g. a known connector tool. After the joining process, the combined casing and new casing provides a retrofit casing. The connector tool should be qualified for well-barrier service and H2S and CO2 exposure, and corrosion and well conditions in general. The sensor unit is now operational to measure the pressure in the closed annulus 440. As shown in Figure 4D, a tubular 410 is run into the well. The tubular 410 is e.g. a completion string, production tubing that is run into the well as part of a completion process. A further inductive transceiver 416 is arranged on or near an exterior portion of the tubular 410. In an embodiment, a depth correlation device is coupled to the inductive transceiver. A cable 418 extends through the well to the further inductive transceiver 416, and provides electrical power and/or data transfer to and/or from the further inductive transceiver 416. Once the tubular is run into the well, the further inductive transceiver 416 is near the inductive transceiver in the sensor unit 426 (which can be confirmed using the depth correlation devices, if these are present), and is able to transfer inductive power to the inductive transceiver for powering the pressure sensor, and is able to receive pressure measurement data that can then be transferred to a remote location (e.g. a platform or onshore location) via cable 418 for processing. A completion string packer 414 is installed between the tubular 410 and the first casing 420, at a height below the top of the cement/barite.

Figure 5 shows a high-level flow diagram describing a method in accordance with Figures 1A to 1C, 2A and 2B. In step S502, a tubular, at least one packer and a pressure sensor are run into a casing, such that the tubular is arranged concentrically within the casing, wherein the at least one packer is configured to provide, in a deployed state, a sealed volume between the exterior of the tubular and an interior surface of the casing, and wherein the pressure sensor is configured to measure a pressure in an annulus behind the casing. In step S504, the at least one packer is deployed, such that the pressure sensor is located in the sealed volume, wherein the sealed volume is connected to the annulus by a perforation in the casing. In step S506, the pressure in the annulus is measured using the pressure sensor.

Figure 6 shows a high-level flow diagram describing a method in accordance with Figures 3A and 3B. In step S602, a hole is created in a casing. In step 604, the hole in the casing is sealed using a plug, wherein the plug comprises a pressure sensor configured to measure a pressure in an annulus behind the casing, and an inductive transceiver for wireless electrical power and/or data transfer. In step S606, the pressure in the annulus is measured using the pressure sensor. Figure 7 shows a high-level flow diagram describing a method in accordance with Figures 4A to 4D. In step S702, a casing located in a well is cut through at a first height, and the portion of the casing above the first height is removed from the well. In step S704, a new casing is run into the well, wherein the new casing is substantially the same or similar diameter as the casing, such that the new casing abuts the portion of the casing in the well, wherein the new casing comprises a pressure sensor arranged on an exterior portion of the new casing. In step S706, a retrofit casing is formed by joining the new casing to the portion of the casing in the well, such that a seal is provided between the new casing and the casing. In step S708, a pressure in an annulus behind the retrofit casing is measured using the pressure sensor.

It will be appreciated by the person of skill in the art that various modifications may be made to the above described embodiments without departing from the scope of the present invention.