WO2025264119A1

WO2025264119A1 - System and method for well integrity testing

Info

Publication number: WO2025264119A1
Application number: PCT/NO2025/050110
Authority: WO
Inventors: Bernt Reinhardt Pedersen; Torger Skillingstad
Original assignee: Exedra As
Current assignee: Exedra As
Priority date: 2024-06-17
Filing date: 2025-06-16
Publication date: 2025-12-26
Anticipated expiration: 2026-12-17
Also published as: NO20240648A1

Abstract

There is disclosed a system for monitoring the integrity of a barrier in a well, the system comprising: - a wellbore termination means, such as a wellhead or a blowout preventer, terminating the well at an upper portion of a wellbore; - a first barrier provided in the well below the wellbore termination means; - a container including, or having included, a fluid to be released below the first barrier in the well so as to establish a pressure gradient across the first barrier; - a pressure sensor connected to the wellbore termination means, the pressure sensor being adapted to sense a change in well pressure There is also disclosed a well including the system and a method of monitoring the pressure integrity of such a well.

Description

SYSTEM AND METHOD FOR WELL INTEGRITY TESTING

The invention relates to a system for monitoring the integrity of a barrier in a well. More particularly, the invention relates to a system where fluid is released below a first barrier in a well, and where a sensor is connected to a wellbore termination means at an upper portion of a wellbore. The invention also relates to a well including such a system and to a method for monitoring the integrity of a barrier in a well.

In the oil and gas industry, safety is always a major concern. Incidents may have severe consequences, such as witnessed in the aftermath of the Deepwater Horizon catastrophe. To prevent such incidents, barriers placed in wells play a leading role. The well barriers are installed mainly to control fluid flow in the well, and ultimately to prevent a blowout, i.e. an uncontrolled release of formation fluids out of the well after the pressure control system, including one or more barriers, has failed.

A barrier set in a well may be said to have two sides: an uphole side and a downhole side. The purpose of the barrier is typically to prevent fluids from moving from the downhole side of the barrier and to the uphole side of the barrier. Thus, the downhole side can be said to be upstream the barrier and the uphole side to be downstream the barrier.

Herein, all references to "above" and "below" a barrier should be construed as closest to surface and closest to the bottom of the well, respectively.

To ensure that a set barrier can withstand a given pressure, it is required to test the integrity of the barrier. Standards, such as NORSOK D-010 relating to well integrity in drilling and well operations, contain detailed requirements/guidelines for testing of well barriers such as cement-based and mechanical plugs. NORSOK D-010 specifies that barriers should be tested in the direction of potential flow, i.e. an upstream test. However, in the industry cement plugs are typically tested from above as no reliable technique currently exists to effectively test them from below. A successful pressure test of a barrier from above, i.e. in the direction opposite to normal flow, does not necessarily indicate that the barrier would withstand the pressure from below. Pressure tests from above have also occasionally been shown to damage casing and other equipment in the well above the barrier. The pressure of a closed-in volume of water is sensitive to temperature changes. For instance, with 1 °C change in water temperature, the pressure change is approximately 4.71 bar. As a result, before the well is thermally stabilised with the environment, it is challenging to detect a pressure change as a result of a leaking barrier.

Attempts have been made to pressure test barriers from below. However, it has been shown to be challenging to localize any detected leak, as it is more or less impossible to verify whether the leak is due to a compromised barrier, or if the source of the leak is another compromised feature in the well, such as another barrier, a casing connection, a valve, a wellhead etc. Further, it can also be challenging to transmit measured pressure data from below and to above the barrier.

In WO 2016/196253 some of the above-mentioned problems are solved by means of a disclosed leak detection system using a tracer gas that is released from below a barrier/plug in the well and a tracer gas detector provided at the wellhead. However, this solution has several drawbacks, in particular in situations where there is no circulation in the well. The distance from the barrier in the well and to the wellhead may be several thousand meters, which in itself creates a delay in sensing any tracer gas that has leaked through the barrier. The leaked gas will then have to percolate all the way to the wellhead in order to be detected. If there is no circulation of mud/fluid in the plugged well, any tracer gas that leaks through the barrier will have to diffuse through the full length of the well from the barrier and to the wellhead through the mud column by means of gravity (percolation) to be sensed by the tracer gas detector. A person skilled in the art will also be aware that, if there is no circulation, the mud column will in most cases have to be saturated by tracer gas before the tracer gas may reach the wellhead as free gas, and that the amount of tracer gas that can be absorbed by the mud increases with increasing depth, which is a consequence of Henry's law. In sum, this implies that the sensitivity of the leak detection system will be low and with a significant time delay due lack of circulation and high absorption of tracer gas in the well. The leak detection system would require a significant amount of tracer gas in order to ensure that the gas may reach the wellhead. In fact, a severe leak, and thus a severely compromised barrier, may never be detected by this leak detection system. Despite alternative solutions for testing the integrity of a well, the industry is searching for a simpler, more time-effective and thereby a lower cost solution for testing the integrity of a well barrier.

The invention has for its object to remedy or to reduce at least one of the drawbacks of the prior art, or at least provide a useful alternative to prior art.

The object is achieved through features, which are specified in the description below and in the claims that follow.

The invention is defined by the independent patent claims. The dependent claims define advantageous embodiments of the invention.

In a first aspect, the invention relates to a system for monitoring the integrity of a barrier in a well, the system comprising:

- a wellbore termination means, such as a wellhead, terminating the well at an upper portion of a wellbore;

- a first barrier provided in the well below the wellbore termination means;

- a container including, or having included, a fluid to be released below the first barrier in the well;

- a pressure sensor connected to the wellbore termination means, the pressure sensor being adapted to sense a change in well pressure.

By the pressure sensor being "connected to" the wellbore termination is meant that the pressure sensor is directly connected to or integrated with the termination means, such as a wellhead or a blowout preventer (BOP), in such a way that it can sense the pressure in the well at the wellbore termination means, such as at the wellhead or BOP. As an alternative to being directly connected to or integrated with the termination means, the pressure sensor may be connected to the termination means via a fluid-connection, such as via a hose, pipe or similar, extending away, and outwardly from the wellbore termination means while still measuring the pressure at the termination means such as at the wellhead or BOP.

The present applicant has surprisingly found that releasing certain fluids from a container to the space below the first barrier so that an overpressure is established below the first barrier, thus creating pressure differential across the barrier, may be sensed almost immediately by a pressure sensor at the wellhead (or BOP) if there is a leak through the first barrier, i.e. in case the integrity of the first barrier is not intact. This means that instead of having to rely on a certain tracer to reach the wellhead from below the first barrier, the release is instead sensed as a pressure increase.

In one embodiment, the fluid to be released from the container may be an inert gas, such as a noble gas. In one embodiment, the gas may be helium gas. In the following helium will be used as an example, but it will be understood that other inert gasses may also be used for the purpose. Surprisingly, helium has been found to have a very low solubility in brine, which is typically the fluid present in an abandoned well. The solubility at 1 atm and 20 °C is about 0.0015 g/kg brine.

In a system according to the invention it is desirable to have a gas with low solubility in waterbased fluids, to obtain a sufficient increased pressure as a result of the injected gas. In general, gases with low solubility in water (i.e., low saturation levels) are those that are non-polar or have low polarity. Helium is non-polar and has been shown to be the gas with the lowest solubility in water of all gases. Other examples of gases with low solubility, and that also can be used in a system according to the invention, include noble gases such as Neon and Argon. Non-polar Nitrogen (N2) and Hydrogen (H2) also have low solubility, however, since H2 is not non-reactive, it may not be eligible to use in a system according to the invention. If the chosen gas is to have a dual purpose, to also act as a tracer for detection, it is desirable to select a gas which is non-existent in the environment where detection is conducted. Hence, N2 may then not be suitable for this purpose in some oil provinces.

At the same time, the bulk modulus of brine is in the order of 2.3 GPa N/m² at room temperature and increasing with pressure. This means that a release of helium that leaks through the first barrier will lead to an increase in fluid mass above first barrier that will be possible to sense as an increased pressure at the wellhead. As an example, the first barrier may be set with its top of cement at a depth of 2000 meters. The casing may be 95/8" and filled with brine. Depending on the inner diameter, the casing in this example will be filled with in the order of 60.000 litres of brine. Adding about 15 litres compressed gas to the brine, will give a pressure increase of around 6 bar, which is well within the sensitivity of modern wellhead pressure sensors. It should be noted that use of helium as a tracer gas has been disclosed in previous patent applications, including by the present applicant. One of the advantages of using helium for such purposes is that the background concentration of helium from the formation is typically very low in many oil provinces. However, in this case, helium is not used as tracer gas, and the presence or non-presence of helium as such is not detected. Instead, it is the unique ability that helium and certain other inert gasses have to create an increased pressure in the well fluid that is utilised. In addition, the pressure-sensing may be combined with a tracer system, i.e. at the system may in certain embodiments include both a pressure sensor as discussed herein and a tracer detector / sniffer to detect the presence or non-presence of a certain fluid, such as an inert gas, such as helium. In one embodiment, releasing fluid below the first barrier may be done by providing the container below the first barrier. However, it should be noted that the invention is not limited to such an arrangement, and that the container may also be provided elsewhere in the well, such as above, including immediately above, the first barrier, with a fluid connection to the space below the first barrier, such as through the first barrier.

In one embodiment, the container may be a pressure canister/vessel. This may be advantageous as no additional equipment for establishing a pressure gradient across the first barrier is needed. In a particularly preferred embodiment, the pressure canister may be positioned below the first barrier in the well. In one embodiment, the pressure canister may be a Balder ™ tool as commercially available from the present applicant. The pressure canister may be pressurised to a pressure of a few hundred bar, such as 200 or 300 bar, or preferably 400 og 500 bar or even higher. However, in an alternative embodiment the fluid may be pressurised by means of a pump provided downhole, where the suction side of the pump may be fluidly connected to the container, while the pressure side of the pump is in fluid connection with the space below the first barrier.

In one embodiment fluid may be released from the container by means of a timer or by means of a remote trigger. If cement is used as material for the first barrier, it is desirable that the cement is fully cured and the well having become substantially thermally stable before the fluid is released from the container. Such curing and thermal stability may typically be reached within 1-2 weeks, but this may of course vary between different well sites. By calculating the fluid volume in the well from above the first barrier (from top of cement) and knowing the volume of gas in the container/canister, the expected pressure increase due to a non-intact first barrier may be estimated. Fluid from the container may be released all at once, or with two or more peaks with time difference between. The peaks may be identical or different. In either case, the pressure release may define a signature that may be easily identified from reading the pressure sensor at the wellbore termination means.

In one embodiment the system may further comprise a second barrier provided below the first barrier in the well. This may be advantageous to confine the released fluid to a limited volume, whereby the increase in pressure and the pressure gradient may be more pronounced. The second barrier may be set a few meters, such as 1, 2, 3, 4, or 5 meters below the first barrier or the second barrier may be set a longer distance from the first barrier, such as 10, 20, 30, 40 or 50 meters below the bottom of the first barrier. In one embodiment, the container / pressure canis- ter may be integrated with the second barrier, such as a bridge plug, such as the above- mentioned Balder ™ tool.

In one embodiment the second barrier may be a packer, which is an easy and relatively inexpensive way to set and establish a closed volume below the first barrier. The second barrier will naturally have to be set before the first barrier in the well. The sealing abilities of a packer, typically secured by elastomers, may deteriorate over time, but initially, when the integrity of the first barrier is to be tested, the integrity of the second barrier packer will typically be sufficient to establish a closed volume under the first barrier. The second barrier may be set in an inner tubing, such as in the production tubing. One or more production packers may at the same time be set to seal an annulus between the inner pipe string, such as the production tubing, and a surrounding pipe string, such as a first casing.

In one embodiment, the first barrier may be a cement plug. In alternative embodiments, the first barrier may be a plug established from loose mass, an epoxy-based resin, quick clay, a bismuth plug, or any other type of plug suitable for plugging of well.

The plug, such as the cement plug, may be set in the full cross-section of the well, such as in a full cross-section inside a casing in the well. If a production tubing or another inner pipe string remains in the well, fluid connection with the annulus outside may be obtained by means of perforation, including by explosives and punching, by section milling, etc. The plug may be set both centrally in the production tubing and in the surrounding annulus, such as the so-called A annulus.

In one embodiment, where the first barrier is a cement plug, the plug may have a length of at least 100 meters, preferably over 200 meters and even more preferably around 300 meters or more. The benefit of having a long cement plug, and even longer than required by various standards, is that it may be possible to leave one or more control cables in the well to be embedded in the first barrier. The cables may or may not be cut over the length of the barrier. An advantage of the present invention and the very precise pressure measurements at the termination means, is that it may be possible to leave the gauge cable(s) in the barrier. Normally, an unbroken cable left in the barrier, may be seen as a possible leak path. However, removing the cable will typically require removing the whole, or at least a parts of, the production tubing over the length of the plug, which is a complicated, time-consuming and expensive process. A downhole line cutter that can cut such a gauge cable without removing the production tubing is disclosed in

WO 2014/126478 Al, and a tool for fully removing the cable without removing the full production tubing is also commercially available from Aarbakke Innovation under the name "Axter". Howev- er, in accordance with the present invention, it may be possible to leave one or more cables in the first barrier un-cut.

After the cement has cured, but before the wellhead / termination means is installed, the top of the barrier is accessible via pipe, coiled-tubing or wireline. During this period, it may be possible to install a hydrophone on top of the barrier to record sound generated by the injection of fluid from the canister. The expansion of the gas will create noise, that may be recorded by a hydrophone placed on top of the barrier. This hydrophone may after the first injection of gas is performed, be pulled back to surface and downloaded. Alternatively it may transmit recorded sound or sound data in real time to surface, via electrical or optical fibre cable. The identification of this sound/noise generated by the injection of gas, may be a proof that the gas has been injected. Also, the duration of the sound can also be used to calculate expected pressure created by the injected gas into volume the closed volume between the first and second barriers.

In one embodiment the system may comprise a remote-operated vehicle (ROV) for reading pressure data from the sensor at wellbore termination means. Reading may be done by visual (camera) inspection of a display at the termination means showing the pressure reading from the well, or the pressure data may be communicated to the ROV by another signal. Alternatively a memory module attached to the pressure gauge/sensor may be removed and optionally replaced with a new memory module by the ROV. The recorded pressures can then, back on surface, be downloaded and analysed. Alternatively or in addition, the system may comprise a signal transmitter and a signal reader for transmitting and reading, respectively, pressure data from the sensor, the reader being located remotely from the wellhead. The transmitter and reader may be an acoustic transmitter and reader, respectively. The signal reader may be provided at an onshore or offshore surface installation, a floating vessel or an autonomous underwater vehicle.

In a second aspect, the invention relates to a well including a system according to the first aspect of the invention. The well may typically be an abandoned well, however the system may also be applicable to use in wells that are temporarily plugged.

In a third aspect the invention relates to a method of monitoring the integrity of a well according to second aspect of the invention, the method including the steps of:

- releasing fluid from the container below the first barrier;

- establishing a pressure differential across the first barrier; and

- monitoring the pressure in the well by means of the pressure sensor at the wellbore termination means. In the following are described an examples of preferred embodiments illustrated in the accompanying drawings, wherein:

Fig. 1 shows a system and well according to the present invention;

Fig. 2 shows a system and well according to a second embodiment;

Fig. 3 shows a system and well according to a third embodiment.

In the following reference numeral 1 will be used to denote a system according to the first aspect of the present invention while reference numeral 10 will be used to denote a well according to the second aspect of the invention. In the figures, same or corresponding elements are indicated by same reference numerals. For clarity reasons, some elements may in some of the figures be with-out reference numerals. The figures are shown highly schematically, and various features therein may or may not be drawn to scale. Any positional indications refer to the position shown in the figures.

Fig. 1 shows a first embodiment of a system 1 and a well 10 according to the invention. The well 10 is shown extending vertically into a surrounding formation F, but may of course also have deviated portions, i.e. portions having a horizontal directional component. The system 1 disclosed below is adapted to test the integrity of a first barrier 2 set in the well 10. The first barrier 2 is here shown as a cement plug set in the full cross-section of the well, i.e. both centrally inside 4 an inner pipe string 6, and in an annulus 8 between the inner pipe string and a surrounding outer pipe string 12. In the shown embodiment the inner pipe string 6 is a production tubing, while the outer pipe string 12 is a casing. The annulus 8 may be the so-called A-annulus. It should be noted however, that the drawings are shown very schematically, and that the well 10 may include further pipe strings and annuli. The well 10 is an abandoned well terminated by means of wellhead 14 at an upper portion 15 of the wellbore. A cable 16 is shown extending from the wellhead 14 and downwardly into the well in the annulus 8 outside the production tubing 6. The cable 16 may be a gauge cable in the form of a bundle of individual cables and tubes and/or a plurality of individual cables and tubes. Such cables and tubes may typically be used (or previously having been used) for signal and power communication, hydraulic supply and/or chemical injection. A pressure sensor 18 is provided on the wellhead 14 and senses the pressure in the annulus 8. The sensor may e.g. be a wellhead subsea pressure transmitter, such as a Model 7540-9000 pressure transmitter commercially available from GP:50 Ltd. The pressure sensor may additionally be adapted to measure temperature and/or depth, i.e. depth at which the pressure sensor is located. In addition or as an alternative, a/the pressure sensor may be used to sense the pressure in the inner pipe string 6.

In the well 10, below the first barrier 2, is provided a container 20 including a gas to be released into the well below the first barrier 2. The container 20 is, in the shown embodiment, a pressure canister connected to an anchor 22 used to anchor the pressure canister 20 in the well 10 insider the production tubing 6.. A second barrier 24 is set below the first barrier in the well 10, so that an isolated volume 26 is established between the first 2 and second barrier 24 inside the production tubing 6, keeping in mind that the anchor 22 as shown in Fig. 1 is not a pressure barrier, in contrast to the embodiments shown in Figs. 2 and 3. In the shown embodiment, the second barrier 24 is provided in the form of a packer. It should also be noted that the isolated volume 26 may typically be significantly smaller than a volume 28 between the top of cement at the first barrier 2 and the wellhead 14, keeping in mind that the figures are not drawn to scale. In one embodiment, the length between the bottom of the cement at the first barrier 2 and the top of the second barrier 24 may be in the order of a few meters, such as 1, 2, 3 of 4 meters and up to around 50 metres, while the length of the upper volume 28 may be in the order of hundreds or thousands of metres. A production packer 30 is set in the annulus 8 towards the lower end of the production tubing to isolate the annulus 8 and secure the production tubing 6 to the casing 12.

When the well 10 is to be abandoned, or pressure integrity of a barrier is otherwise to be tested, one or more perforations 32 are made in the production tubing 6, establishing fluid connection between inside of the productions tubing 6 and the annulus 8. The perforations may be made by explosives, punching, milling, abrasive cutting or other suitable means. Additional, subsequent cleaning of the annulus 8 may or may not be performed. The packer defining the second barrier 24 in this embodiment is set in the well 10 inside the production tubing 6 below the level of the perforations 32. The pressure canister 20 is then anchored to inside the production tubing 6 above the second barrier 24. Cement is subsequently filled into the well inside the producing tubing 6 and out into the annulus 8 by a not shown cementing tool lowered into the well. Cementing may alternatively be performed by "bull-heading", i.e. forced pumping, through the inner pipe string 6, such as via a not shown production line from a production unit. A separate not shown anchor may be used to define the lower end of the cement barrier 2 or alternatively the anchor 22 used with the pressure canister 20 may be also serve as a fundament for the cement barrier 2 in the well 10.

After the cement has cured and the well 10 has stabilised thermally, typically within 1-2 weeks from cementing, pressurised fluid, typically in the form of a pressurised gas, such as an inert gas, e.g. helium, is released from the pressure canister 20. Release may in certain embodiments be triggered by a control unit including a timer, which after a pre-determined time opens a valve to release the pressurised gas into the isolated volume 26 between the first and second barriers 2, 24. The gas may be released once, twice or more times, where the latter may generate two or more pressure peaks that will give the release a certain "signature".

It should be noted of course that the first barrier 2 does not have to be cement, and that the gauge cable 16 may indeed still be cut. In one specific, not shown embodiment, the first barrier may be a bismuth plug with a length of 2-20 meters, preferably 3-10 meters. The gauge cable may be cut and optionally also removed from the length of the plug.

The gas released into the closed volume 26 may or may not be a gas that is naturally occurring in the well. In contrast to use of tracers to distinguish the source of a leak, the system 1 according to the present invention instead monitors pressure increase at the wellhead 14. By establishing a sufficiently long first barrier 2, here cement plug, the gauge cable 16 may be left in the annulus without being cut, as discussed above. However, in other embodiments the gauge cable (or plurality of cables) may be cut and potentially pulled out from the well 10.

The pressure canister may have a volume in the range 5-50 litres, such as 10, 20, 30 or 40 litres. The amount of gas needed, and the release pressure will depend on the specific application and the depth of the first barrier 2 in the well. In one embodiment, the pressure in the pressure canister 20 may be in the order of several hundred bars, such as around 500 bars. Releasing the pressurised gas in the closed volume 26 will increase the mass and hence the pressure in the closed volume 26 to generate an over-pressure compared to the pressure in the volume 28 above the first barrier, keeping in mind that well is pressure-balanced when the first and second barriers 2, 24 are set, thus establishing a pressure gradient across the first barrier 2. The pressure gradient will attempt to equalise the pressure across the first barrier 2. However, if the first barrier 2 is working as intended, then no pressure equalisation will take place, and the pressure gradient will remain. On the other hand, if the integrity of the first barrier is not intact, fluid from the isolated volume 26 below the first barrier will be driven across the first barrier to the volume 28 above the first barrier 2, increasing the mass in the volume 28 above the first barrier 2 and thereby the pressure above the first barrier 2. An increase in pressure will be sensed by the pressure sensor 18, here shown sensing the pressure in the annulus 8, which in the shown embodiment is the so- called A annulus. The increase in pressure will depend on the volume 28 above the first barrier 2 in the well 1O₇ the amount and pressure of gas released from the canister 20, the type of gas used etc. Reference is made to the example presented above in the general part of the description.

Fig. 2 shows an abandoned well 10, where a remote-operated vehicle (ROV) 34 is connected to a not shown vessel or surface installation by means of the tether 36. The ROV 34 is equipped with a sensor reader 38, here in the form of a camera, to read pressure data and/or to retrieve logged pressure data from the sensor 18 at the wellhead 14. The read pressure data may be stored in memory in the ROV 34 and/or communicated from the ROV 34 topside via the tether 36 or wirelessly. The ROV 34 may additionally or alternatively retrieve a not shown memory module with stored pressure readings, located on the pressure sensor 18, and optionally insert a new memory module for further pressure logging. The module(s) can then be downloaded and analysed at surface. In contrast to the embodiment shown in Fig. 1, the anchor 22, to which the pressure cannis- ter 20 is connected defines the second barrier 24 in the well, whereby the isolated volume 26 below the first barrier 2 is defined by the even smaller volume between the anchor 22 and the lower portion of the first barrier 2. In this embodiment, the combined second barrier 24 with anchor 22 and pressure canister 20 may be a Balder ™ tool commercially available from the present applicant, where the combined anchor/barrier is a bridge plug with a not shown feed-through for the pressurised gas.

Fig. 3 shows an alternative embodiment of a well 10 where the sensor 18 includes a transmitter 40, here in the form of an acoustic transmitter, communicating (acoustically) with a remote signal reader 42. The signal reader 42 may be provided on a (not shown) surface installation (onshore or offshore), a floating vessel, an ROV, an autonomous underwater vehicle, etc. Similarly to what was shown in Fig. 2, the anchor 22 defines the second barrier 24.

It should be noted that the above-mentioned embodiments illustrate rather than limit the invention, and that those skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. Use of the verb "comprise" and its conjugations does not exclude the presence of elements or steps other than those stated in a claim. The article "a" or "an" preceding an element does not exclude the presence of a plurality of such elements.

The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measures cannot be used to advantage.

Claims

C l a i m s

1. System for monitoring the integrity of a barrier in a well, the system comprising:

- a wellbore termination means, such as a wellhead or blowout preventer, terminating the well at an upper portion of a wellbore;

- a first barrier provided in the well below the wellbore termination means;

- a container including, or having included, a fluid to be released below the first barrier in the well so as to establish a pressure gradient across the first barrier;

2. System according to claim 1, wherein the fluid to be released from the container is an inert gas.

3. System according to claim 2, wherein the gas is helium.

4. System according to any one of claims 1-3, wherein the container is a pressure canister.

5. System according to any one of the preceding claims, wherein the system further comprises a second barrier provided below the first barrier in the well.

6. System according to claim 5, wherein the second barrier is packer.

7. System according to any one of the preceding claims, where in the first barrier is a cement plug.

8. System according to claim 7, wherein the cement plug is set if the full cross-section of the well.

9. System according to claim 8, where in the cement barrier is at least 100 meters long, preferably over 200 meters and even more preferably around 300 meters or more.

10. System according to any one of the preceding claims, wherein the system further comprises a gauge cable extending into the well, where at least a portion of the gauge cable is embedded in the first barrier.

11. System according to any one of the preceding claims, wherein the system further comprises a remote-operated vehicle for reading pressure data from the sensor at the wellbore termination means.

12. System according to any one of the preceding claims, wherein the system further com- prises a signal transmitter and a signal reader for transmitting and reading, respectively, pressure data from the sensor, the reader being located remotely from the wellhead.

13. System according to claim 12, wherein the signal transmitter and reader are an acoustic transmitter and reader, respectively.

14. Well including a system according to any one of the preceding claims.

15. Well according to claim 14, wherein the well is an abandoned well.

16. Method of monitoring the integrity of a well according to claim 14 or 15, the method including the steps of:

- releasing fluid from the container below the first barrier;

- establishing a pressure differential across the first barrier; and

- monitoring the pressure in the well by means of the pressure sensor at the wellbore termination means.