Background

[0001] This disclosure relates to the field of subsurface wellbore completion and instrumentation. More specifically, the disclosure relates to methods for repairing and/or retrofitting instrumentation in a completed well annular space called the “B” annulus.

[0002] Subsurface wells, such as those used to extract hydrocarbons from permeable rock reservoirs, typically comprise an internally nested pipe called a “tubing string” for production of fluids to surface or injection of fluids from surface, a first external casing or liner nested outside the tubing string to a selected depth in the well, and a second external casing nested outside the first external casing to a shallower depth, e.g., to a depth sufficient to protect and isolate certain formations such as fresh water bearing formations. Sometimes, depending on well depth, complexity, local requirements, etc., one or more additional casing strings, or so-called conductor pipe may be nested outside the second external casing. The annular space between the tubing string and the first external casing is called the “A annulus.” The annular space between the first external casing and the second external casing string is referred to as the “B annulus.”

[0003] As a well is operated for fluid production from a reservoir, the warmer reservoir liquids and/or gas heat up the entire wellbore, causing a pressure increase in the annuli due to the annuli being sealed off at surface in a valve assembly called the “wellhead” and the lower end of the casing strings in the respective annuli by a packer or other annular seal device. The A annulus typically has a pressure gauge and a valve system in the wellhead such that pressure therein can be monitored and if necessary relieved. The B annulus seldom has a pressure gauge or relief valve, in particular in subsea wellheads, which are disposed on the water bottom. It should also be noted that a pressure increase in either annulus may be due to failed or faulty sealing at the lower end of the respective casing strings. [0004] As a result, pressure build-up in the B annulus may not be known because it is not ordinarily measured. Because of a lack of B annulus pressure measurement, a number of incidents worldwide have occurred where a wellhead seal is compromised, sometimes to critical failure. Therefore, it is common practice to shut in wells where an increase in B annulus pressure, also referred to as sustained casing pressure, is observed to avoid possible seal failure. Such incidents may include lost production, which may incur great financial loss for the well owner. Also, when performing artificial lift operations, in particular gas lift, which requires pressure to be applied to the A annulus, there is a concern that pressure may leak from the A annulus into the B annulus. Therefore, a B annulus measuring system would be of interest.

[0005] Newer wells may have a sensor system mounted on the production casing in order to measure pressure in the B annulus. Such sensor systems may comprise wireless transmitting measurements from sensors (e.g., pressure sensors) to an electrical cable- connected system mounted on the exterior of the tubing string. Several technology providers, for example, Emerson Electric Company, provider of the ROXAR downhole wireless system (https://www.emerson.com/en-us/catalog/roxar-downhole-wirele ss) and Schlumberger Technology Corporation, provider of the METRIC ECLIPSE B-annulus pressure and temperature monitoring system (https://www.slb.com/completions/well- completions/permanent-monitoring/permanent-downhole-gauges/m etris-eclipse) provide B annulus measuring such systems for new wells that may be installed during well construction. However, the vast majority of older wells, and some newer wells do not have these monitoring systems incorporated. Therefore, there is need for a B annulus sensor system that can be retrofitted into wells without replacing the casing to avoid well shut-ins and lost production.

Summary

[0006] One aspect of the present disclosure is a method for controlling and/or measuring pressure in a well annulus. A method for measuring and/or controlling pressure according to this aspect, in an annular space between a first casing string nested within a second casing string in a subsurface well includes moving a well intervention tool to a selected depth in the first casing string. An opening is created in the first casing string using the well intervention tool. Fluid movement through the opening is constrained to a predefined path inside the first casing string; and the predefined path is fluidly connected to at least one of a pressure sensor or a valve, the valve controlling fluid connection between the predefined path and an interior of a well tubing inserted into an interior of the first casing string.

[0007] In some embodiments, the well intervention tool comprises a mill or drill to create the opening in the first casing.

[0008] In some embodiments, the constraining fluid movement comprises setting an annular seal inside the first casing, the annular seal comprising axially spaced apart seals to close an annular space between the first casing and the well tubing.

[0009] In some embodiments, the annular seal comprises a fluid passage to the at least one of the pressure sensor or the valve, wherein the at least one of the pressure sensor or the valve is disposed inside the well tubing.

[0010] In some embodiments, the annular seal comprises a sliding sleeve valve operable to selectively open and close a fluid passage from the annular space between the well tubing and the first casing to the interior of the well tubing, the fluid passage having a port disposed in the annular space, a pressure sensor disposed in the annular space and in fluid communication with the port.

[0011] In some embodiments, the annular seal comprises an axial fluid passage across the annular seal to enable fluid movement in the annular space.

[0012] In some embodiments, the annular seal comprises a valve in the axial fluid passage.

[0013] In some embodiments, the well intervention tool comprises a pressure sensor disposed along a flexible shaft drill, the flexible shaft drill creating the opening and emplacing the pressure sensor in the opening in the first casing so as to be exposed to fluid pressure between the first casing and the second casing. [0014] In some embodiments, the well intervention tool is conveyed into the well through the interior of the well tubing.

[0015] In some embodiments, the well intervention tool is conveyed on an exterior of the well tubing when the well tubing is placed inside the first casing.

[0016] A method for measuring pressure in an annular space between a first casing string in a well nested within a second casing string in a well according to another aspect of the present disclosure includes attaching a plurality or axially spaced apart calipers on an exterior of a well tubing. The well tubing is inserted inside the first casing string. A diameter of a space between the tubing and the first casing string is measured using the axially spaced apart calipers. A pressure in the annular space is determined based on the measured diameter and a measured pressure inside the well tubing.

[0017] Other aspects and possible advantages will be apparent from the description and claims that follow.

Brief Description of the Drawings

[0018] FIG. 1 illustrates a wellbore with conventional tubular pipe strings that may be retrofit using a method according to the present disclosure.

[0019] FIGS. 2 A, 2B and 2C illustrate how a wellbore tubular string is prepared for a retrofit B annulus sensing system according to the present disclosure.

[0020] FIG. 3 illustrates a sleeve that may be used for temporary sealing off the tubular penetration shown in FIG. 2.

[0021] FIG. 4A and FIG. 4B illustrate that a tubing string has been installed in the wellbore, including a sensor unit mounted on the tubing string to monitor one or more physical parameters in the B annulus.

[0022] FIG. 5 illustrates a monitoring sub that has shifted the sleeve of FIG. 3 downward allowing pressure monitoring.

[0023] FIG. 6 illustrates a method and devices where dimensional changes of tubulars due to pressure variations are monitored. [0024] FIG. 7 illustrates a method where an intervention tool is run inside the tubing to operate a pack off sub pre-installed on the tubing, wherein the pack off sub can be opened to establish and control fluid flow between the tubing and the B annulus.

[0025] FIG 8 illustrates the opening of a sleeve to allow access to the inside wall of the production casing.

[0026] FIG. 9 illustrates the penetration of the casing wall as well as the penetration tool in the middle position.

[0027] FIG. 10 illustrates the sub is closed, and the intervention tool is ready to be removed.

[0028] FIG. 11 illustrates that the production tubing has been removed prior to re completing well.

[0029] FIG. 12 illustrates a well intervention tool hoisted inside the casing, ref. FIG. 11, placed at desired depth of operation into the wellbore casing.

[0030] FIG. 13 illustrates a self-drilling semi-flexible sensor module, ref. FIG. 12, being drilled through the casing with an inclination.

[0031] FIG. 14 illustrates a self-drilling semi-flexible sensor module being fully inserted into the penetrated hole in the casing string.

[0032] FIG. 15 illustrates a production tubing installed inside the casing with a wireless power and communication device to the pre-installed sensor module, clamped to the production tubing.

[0033] FIG. 16 illustrates a plug installed between the casing and tubular wall in such a way that the walls are forced apart, allowing for more radial space.

[0034] FIG. 17 illustrates a self-drilling semi-flexible sensor device drilled through the casing. A seal behind the drill-bit will ensure a sealing between annulus B to annulus A. A hole inside the device will lead fluid to the pressure transducer.

[0035] FIG. 18 illustrates the cross-section of the sub with self-drilling semi-flexible sensor device. [0036] FIG. 19 illustrates a plug installed in the wall of casing or tubular in such a way that the walls are forced apart allowing for more radial space for installation of various plugs, valves and measurement devices.

Detailed Description

[0037] The present disclosure sets forth methods to penetrate a first tubular string in a well, such as a casing or liner nested within a second tubular string such as a casing or liner, when production tubing is removed from the well. The penetration may be followed by various methods of implementing a monitoring system to observe conditions in the “B annulus.” Also, the present disclosure sets forth methods to bleed off pressure in the B annulus or relieved for wells in which no pressure relief valve at surface has been implemented, including without limitation wells in which the B annulus is disposed inside a well tubular referred to as a liner, wherein the exterior nested pipe does not extend back to the surface (or water bottom in marine wells).

[0038] Wellbore intervention tools, which may be conveyed into a well using winch- based conveyance such as wireline, slickline, coiled tubing or semi-stiff spoolable rod, have been developed that can drill or mill openings through a tubular string in a well. Such tools or other tools can penetrate the tubular string with, e.g., a drill or mill and then install a device, for example a bolt or plug, into the openings so drilled or milled. An example of such a tool is known as the MicroTube Remover Wellbore Intervention Tool, provided by Aarbakke Innovation AS, the assignee of the present disclosure. The foregoing tool and its operation are more fully described in US Patent No. 10,370,919 issued to Hansen et al. The foregoing tool can be used for a number of operations in wellbores, from machining and drilling to the insertion of sensors, valves, etc. It should be understood that other devices for creating openings in well tubulars that may be used in accordance with this disclosure include, without limitation, shaped explosive charges and chemical cutters. A possible advantage of using a drill or mill as with the tool disclosed in the ‘919 patent is the ability to control the lateral extent of the drilling or milling to avoid penetrating the outermost casing or liner, in which the casing to be penetrated is nested. [0039] For purposes of defining certain features of a completed well according to the present disclosure, the following may apply. Wells used for production of or injection of fluid, as explained in the Background section herein may comprise a first tubular string referred to as a “casing”, which is inserted into the borehole created by drilling. The casing mechanically protects and hydraulically seals exposed formations penetrated by the borehole. The casing generally extends back to the surface expression of the well (or water bottom expression in marine wells) and may terminate within a valve assembly called a wellhead. It is ordinarily the case that the casing is cemented in place in the borehole and is not readily removable from the well.

[0040] A smaller diameter tubular string, referred to as a production tubing or simply

“tubing” may be nested within the casing. The tubing provides a small cross section conduit such that the flow velocity of fluid to surface may be increased over the velocity that would occur absent the tubing. Such increased velocity may enable lifting more dense liquids (e.g., water) to reduce hydrostatic loading of the well when such liquids would otherwise accumulate in the well and exert hydrostatic pressure against the reservoir formation. In many cases the tubing is locked into place at a selected depth inside the casing in an annular seal known as a “packer”, which closes to fluid flow the annular space between the tubing and the casing. The tubing also extends to the surface expression of the well and terminates in the wellhead. The tubing is ordinarily inserted into the well after the last (innermost nested) casing is installed in the borehole, and the tubing is ordinarily removable from the well. Tubing may be in the form of spoolable pipe, such as coiled tubing, or in the form of jointed tubes assembled by connecting threaded couplings at the axial ends of each tubular segment.

[0041] Many wells are drilled to depths and through subsurface formations having mechanical properties and internal fluid (pore) pressures such that it is required to provide one or more further tubular strings, which may be referred to herein as at least a “second casing” within which the first casing and the tubing are nested, to isolate and protect such formations. [0042] The annular space between the tubing and the outer adjacent nested tubular string

(i.e., the first casing) is referred to as the A annulus, while the annular space between the first casing and a further, outer nested tubular string outside the first casing may be referred to as the B annulus. The A annulus in most cases extends to the wellhead and is provided with a valve within the wellhead that can be used to vent pressure in the A annulus as may be needed. The wellhead expression of the A annulus also makes practical measurement of pressure therein by means of any known pressure gauge or sensor. As explained in the Background section herein, in many wells, the B annulus either is not expressed at or in the wellhead and/or does not have any valve in the wellhead to enable pressure measurement or adjustment within the B annulus.

[0043] For purposes of the present disclosure, the term “tubular string” may be used to mean any length of pipe, conduit, tube or the like that extends along a well and within which the production tubing is nested. Such tubular string may be a casing, which extends the entire length of the well from its greatest depth up to a wellhead at the top of the well (which may be at the water bottom in a marine well). The casing may be nested within another tubular string, which may also be a casing that extends from an intermediate depth to the wellhead. The A annulus and B annulus between the respective nested tubular string have been defined above. As used herein, “casing” may be used to mean a tubular string that is not ordinarily removable from the well, e.g., by reason of being cemented in place. A “tubing” as used herein means the innermost nested tubular string or nested tubular strings, which does not directly contact any subsurface formation at any place along the well, and which is ordinarily removable from the well.

[0044] There are pressure sensors known in the art that use wireless communication between a sensor in fluid communication with or disposed in the B annulus, and a sensor communication system placed in the A annulus. Such A annulus system is typically powered by an electrical cable strapped or clamped to the exterior of the production tubing. Such electrical cable may be fed through a suitable seal arrangement in the wellhead to a power supply and data acquisition system at the surface. In some cases, the electrical cable may also be used to power sensors further down in the wellbore, used, for example, for fluid production control and subsurface formation reservoir monitoring. The foregoing systems may be referred to as downhole permanent gauge systems. These downhole permanent gauge systems can be installed in newly constructed wells, mounted externally on the inner nested casing when such casing is “run” into the drilled borehole, but there are no known systems available that can be retrofitted into wellbores without having to retrieve and replace the casing. This disclosure sets forth methods for retrofitting a B annulus monitoring apparatus to an already completed well (that is, a well with an innermost nested casing already in place) and describes how such apparatus can be configured used to release pressure in the B annulus if and as required.

[0045] FIG. 1 illustrates a well 10 with typical tubular strings installed. A production tubing (“tubing” hereafter for convenience) 12 extends from a wellhead (not shown in the drawing figures) for production of fluid from a subsurface reservoir (not shown) or injection of fluid into a subsurface reservoir. The tubing 12 may be nested within a first casing string 14, and may extend in general to a depth in the well 10 above the subsurface reservoir (not shown). The first casing string 14 may extend to the deepest drilled depth point in the well 10 to ensure that all formations penetrated by the borehole have been properly sealed and protected. The A annulus 18 is the annular space between the tubing 12 and the first casing string 14. The fist casing string 14 may be nested within a second casing string 16. The second casing string 16 may extend to a shallower depth in the borehole than the first casing string 14, for example, to hydraulically and mechanically isolate shallower formations such as fresh water bearing formations or low fluid pressure formations when the well 10 is drilled through overpressured or underpressured formations at greater depth. FIG. 1 is directed to the upper part of the well 10, below the wellhead (not shown) with its casing hangers, tubing hanger, etc., yet shallower than the depth to which the second casing string 16 is set.

[0046] Along the exterior of the tubing 12, there may be a control line/cable 22, which may comprise an hydraulic control line and electrical and/or other (e.g., optical fiber) cable. The control line/cable 22 may be used for, e.g. (none of which are shown separately herein) operating a downhole safety valve, operating and communicating with downhole sensors and communication devices, valves, etc. Across each tubing segment coupling, which may be threaded couplings, a cable clamp (also referred to as a cross coupling cable protector) 22A may be installed to hold the cable(s) and/or control line(s) 22 in place, support the weight of the foregoing and protect them from physical damage during deployment and retrieval of the tubing 12 from the well 10. The control line/cable 22 may comprise a section, shown at 22B, wherein the control line/cable 22 may be looped around the exterior of the tubing 12 to provide extra length of the control line/cable as may be needed from time to time.

[0047] FIG. 2 A illustrates how the first casing string 14 may be prepared for installing a retrofit B annulus sensor (not shown in FIG. 2A). In FIG. 2A, the tubing (12 in FIG. 1) and its externally mounted components (in FIG. 1, the control line/cable 22, cable clamps 22A and coil 22B) have been removed from the fist casing string 14, leaving an internal bore 18A inside the first casing string 14.

[0048] FIG. 2B shows an opening 14A formed in the first casing string 14, whereby fluid communication between the B annulus 20 and the internal bore 18 A is established. The opening 14A may be formed, for example, using a tool as described in the Hansen et al. ‘919 patent set forth earlier herein. How the opening 14A is formed is not a limitation on the present disclosure, as there are several techniques for creating the opening which are well known for those skilled in the art. Examples can be, without limitation drilling, milling, punching, perforating with an explosive charge or chemical charge, etc.

[0049] Following forming the opening 14 A, and referring to FIG. 2C, the opening 14A may be left open, or it may be temporarily closed off by inserting a sealing device 14B that can be removed for subsequent operations (e.g., a so-called “knock-out plug”) by an associated tool, again, such as the Multifunction tool set forth above. In some embodiments, the sealing device 14B can be a burst disc, where the sealing device 14B is opened by pumping fluid into the internal bore 18A until the burst pressure is exceeded. The internal surface of the first casing string 14 above and below the opening 14A may be honed, for example, by a wellbore intervention tool immediately after the opening 14A has been formed, to improve sealing when a sealing device (see, e.g., FIG. 3) is later to be placed in the first casing string 14 across the opening 14A. [0050] FIG. 3 shows an example embodiment of a sealing sleeve 24 that may be used for temporary sealing of the opening 14A. The sealing sleeve 24 may comprise a seal mandrel 24B shaped to move along the interior wall of the first casing string 14. The mandrel 24B may comprise axially spaced apart seals 24A to sealingly engage the interior wall of the first casing string 14. The sealing sleeve 24 may be installed on the interior wall of the first casing string 14 by a wellbore intervention tool, for example a wireline, slickline or coiled tubing conveyed tool to a depth in the first casing string 14 such that the seals 24A are disposed above and below (axially on opposed sides) the opening 14A so as to seal the opening 14A to fluid flow into the first casing string 14 except through the sealing sleeve 24. The sealing sleeve 24 may be moved again when the tubing (12 in FIG. 1) and associated components are installed inside the first casing string 14, or by a wellbore intervention tool when the tubing (12 in FIG. 1) is not present in the well.

[0051] FIGS. 4A and 4B show, in vertical cross-section and horizontal cross section, respectively, that the tubing 14 has been once again installed in the well 10. In the present example embodiment, a sensing unit 30 may be disposed on the exterior of the tubing 12. The sensing unit 30 may comprise a housing 30B within which may be disposed a pressure sensor and communication devices (not shown separately) to monitor the B annulus 20 pressure and communicate measurements of such pressure to surface, e.g., along the control line/cable 22. The housing 30B may comprise axially spaced apart seals 30A that can isolate an axial interval along the interior of the first casing string 14. When the tubing 14 is landed in the wellhead (not shown), the sensing unit 30 is spaced out to seal above and below the opening 14A. The seals 30A may be elastomers activated in a manner as are downhole production packers or the seals 30A may be metal-to-metal seals. The seals 30A may be activated, for example by pressurizing the sensing unit 30 from within the tubing 12. The control line/cable 22 can be fed through the sensing unit housing 30B through axial bores 30C, or they may be sealed above and below the sensing unit 30 using known tube fittings. There may be one or more such bypass ports 30C between the upper and lower axial ends of the sensing unit 30, allowing fluid circulation. One way valve(s) (not shown) may be built into these bypass ports 30C in some embodiments.

[0052] An electrical cable can be used between the wellhead and the sensing unit 30 to read and transmit the signals from the sensor built into the sensing unit 30, measuring pressure from the B-annulus through the opening 14A (i.e., the casing penetration). The foregoing cable may be the control line/cable 22 as used for the permanent gauge(s) mounted lower in the wellbore, where also the sensor incorporated into the sensing unit 30 can be of the same type as the downhole permanent gauge(s). In some embodiments, the sensing unit 30 may comprise a remotely operable valve (not shown separately) that enables selective hydraulic communication between the B annulus 20 and the A annulus 18, or into the tubing 12. Such valve in the sensing unit 30 may be operated by a wellbore intervention tool or via the control line/cable 22 used for the sensor(s). Following fluid and/or gas circulation or venting, the valve may be closed again by the same method.

[0053] FIG. 5 shows in some embodiments that the sensing unit 30 may be used to move the sealing sleeve 24 previously explained with reference to FIG. 3 axially along the interior of the first casing string 14, allowing pressure monitoring of the B annulus 18 through the opening 14A while maintaining pressure isolation between the B annulus 20 and the A annulus 18. The downward axial movement of the seal sleeve 24 may be performed, e.g., by a latch 30D or similar device in the lower end of the sensing unit 30 that attaches to the seal sleeve 24. In this way the sealing sleeve24 may be moved upward again when the tubing 12 is lifted, such that the sealing sleeve 24 once again may straddle and thereby seal the opening 14A when the tubing 12 is moved within the well for any reason. In such case, the latch 30D may be released so that the sensing unit 30 is released from the seal sleeve 24 when the seal sleeve 24 is positioned to seal off above and below the opening 14A

[0054] FIG. 6 illustrates a second method and device for detecting the B annulus pressure. One or more internal calipers 32 may be affixed to the exterior of the tubing 12 and oriented to measure internal diameter of the first casing string 14, and in some embodiments, external diameter of the tubing 12. Dimensional changes of the first casing string 14 and the tubing 12 which may result from pressure changes in the B annulus may thereby be monitored. This is a result of the fact that a tubular that is pressurized internally increases slightly in diameter or decreases if exposed to external pressure. Therefore, if a pressure outside of the tubing 12 varies, then the inner diameter of the first casing string 14 will change, as will the diameter of the tubing 12. Now, if the first casing string 14 diameter change is measured with reference to the diameter change of the tubing 12, and knowledge of the pressure internally and externally of the tubing 12, the pressure externally of the first casing string 14 can also be calculated. As can be observed on the illustration, one or several calipers 32 that measure the dimensional changes can be installed in the well, e.g., on the exterior of the tubing 12. The measurement method can be performed several ways, for example, by measuring the pressure within a hydraulic chamber effected by a mechanical contact between the tubing 12 and the first casing string 14, by strain gauges affixed to the tubing 12 and first casing string 14, by position sensors, acoustic distance (range) sensors, among others. A possible advantage of measuring tubular dimensions as shown in FIG. 6 to determine B annulus pressure is that the first casing string 14 does not need to be penetrated as in the example embodiments explained with reference to FIGS. 2 through 5. Pressure accuracy may be improved if the first casing string 14 is penetrated initially using a sensing unit as explained with reference to FIG. 4 and measuring pressure over a number of different well operating conditions. The opening (14A in FIG. 4) may subsequently be plugged prior to installing the caliper(s) as described herein.

[0055] FIGS. 7 through 10 illustrate another method for measuring pressure in the B annulus, where a pack off sub is deployed into the wellbore mounted onto the tubing string. In FIG. 7, the pack off sub 70 may comprise a cylindrical pack off sub body 70A that may be coupled within the tubing 12 such as by engaging threaded connections between joints of jointed tubing, or by affixing to the exterior of a jointed tubing or a continuous tubing such as coiled tubing. The pack off sub body 70A may comprise axially spaced apart seals 72 to seal the A annulus 18 across the pack off sub 70. The pack off sub body 70A may comprise one or more axial fluid flow ports 74 which enable movement of fluid along the A annulus 18 and/or passage of cables and tubes longitudinally by the pack off sub 70. The one or more axial flow ports 74 may comprise any form of valve 74A therein to control fluid flow across the pack off sub 70 as may be desired. The pack off sub body 70A may comprise a radial fluid port 76 disposed longitudinally between the seals 72. The radial fluid port 76 may thereby be sealed against flow longitudinally along the pack off sub 70, but may provide a fluid port to communicate with one or more sensors 71, e.g., a pressure sensor such that fluid conditions, e.g., pressure in the radial fluid port 76 may be measured and communicated to surface. As will be explained further below, the radial fluid port 76 may be sealingly engaged with an opening to be made in the casing 14 such that pressure in the B annulus20 may be measured, and as will be further explained, adjusted if and as necessary.

[0056] A valve 73 such as a sliding sleeve valve may selectively open and close fluid communication between the radial fluid port 76 and an interior of the tubing 12 as may be desired. The sliding sleeve valve 73 is shown closed, whereby fluid pressure at the radial fluid port 76 is isolated from the interior of the tubing 12. A well intervention tool 82, for example, the multifunction well penetrator tool as described in US Patent No. 10,370,919 issued to Hansen et al. may be lowered through the interior of the tubing 12 to perform certain operations as will be explained below. The intervention tool 82 may comprise a penetrator 78 such as a rotary drill or mill, that may be extended from the intervention tool 82 to create an opening in the casing 14 to establish fluid communication with the B annulus 20.

[0057] In FIG. 8, the intervention tool 82 is moved so that the penetrator 78 is axially aligned with the radial fluid port 76. The (sliding sleeve) valve 73 is moved to its open position. In FIG. 9, the penetrator 78 is radially extended from the intervention tool 82 to engage the tubing 12, the casing 14 and create an opening 80 in the tubing 12 and the casing 14, thereby establishing fluid communication with the B annulus 20. FIG. 9 illustrates the opening in the tubing wall allowing fluid communication between the A annulus 18 and the B annulus 20. The opening 80 in the casing wall can be fitted with any one or more of different types of valves and plugs, depending on intended uses and functions. These can be, but not limited to, one-way valves and pressure activated valves. [0058] In FIG. 10, the penetrator 78 is retracted into the intervention tool 82 and the intervention tool 82 is being withdrawn from the tubing 12. FIG. 10 illustrates that the (sliding sleeve) valve 76 is in a closed position, preventing uncontrolled flow into the interior of the production tubing 12, while maintaining fluid communication between the B annulus 20 and the radial fluid port 78. The sensor 71 remains in fluid communication with the B annulus 20 through the radial fluid port 76. In the event it becomes necessary or desirable to adjust fluid pressure in the B annulus 20 the sliding sleeve valve 73 may be operated to selectively establish fluid communication between the interior of the tubing 12 and the B annulus 20.

[0059] FIG. 11 shows a well 10 wherein the tubing (12 in FIG. 1) has been removed prior to re-completing the well using another example embodiment according to the present disclosure. The first casing string 14, second casing, internal bore 18A and B annulus 20 are similar to those explained with reference to other embodiments described herein.

[0060] FIG. 12 illustrates an intervention tool 50 being inserted inside the first casing string 14 wherein the tubing has been removed as explained with reference to FIG. 11. The intervention tool 50 may be moved through the well 10 by a spoolable conveyance 52, such as armored electrical cable, coiled tubing or slickline, although the foregoing conveyances are not limitations on the scope of the present disclosure. The intervention tool 50 is placed at a desired axial position or depth D in well 10. The intervention tool 50 may be provided with an internal drilling tool deflector, called a whipstock 50A, to angularly deflect (reorient the rotary axis) of an axially flexible, torsionally rigid drill shaft 50B, onto which a rotary mill or drill 50D (hereinafter drill bit for convenience) may be mounted at a longitudinal end to be rotated so as to penetrate the wall of the first casing string 14. The whipstock 50A may be in the form of a guide bore in the housing of the intervention tool 50 that generally causes the flexible shaft 50B to remain straight while the flexible shaft 50B is disposed within the whipstock 50A. A semi-flexible sensor module 50C may be attached to the drill shaft 50B. The flexible drill shaft 50B may be longitudinally extended from the body of the intervention tool 50 to cause the drill bit 50D to penetrate the wall of the first casing string 14. The semi-flexible sensor module 50C may comprise one or more sensors, e.g., pressure sensors, disposed along the flexible shaft 50B generally behind the drill bit 50D.

[0061] FIG. 13 illustrates the drill bit 50D having penetrated the wall of the first casing string 14, and entering the B annulus 20 at an inclination with respect to the axis of the first casing string 14 and the B annulus 20. As the flexible shaft 50B extends into the B annulus 20, the sensor module 50C is moved as well into the B annulus 20. The drill-bit 50D will only penetrate the first casing string 14, and be deflected by the second casing string 16 because the flexible shaft 50B will no longer be held along a single axis once it leaves the whipstock 50A. When the flexible sensor module 50C contacts the wall of the second casing string 16, the flexible sensor module 50C will also bend along with the flexible shaft 50B to accommodate the B annulus 20 longitudinally.

[0062] FIG. 14 illustrates the flexible sensor module 50C being fully inserted into the B annulus 20. The longitudinal end of the semi-flexible sensor module 50C, that is, the end opposed to the end proximate the drill bit 50D is provided with a seal 50C-1 that will seal radially between the drilled hole and the inserted semi-flexible sensor module 50C, thereby fluidly isolating the B annulus 20 from the internal bore 18A (and thereby the A annulus once the tubing is re-inserted into the first casing string 14).

[0063] FIG. 15 illustrates the tubing 12 being re-inserted inside the first casing string 14.

The tubing 12 may have disposed thereon a wireless power and communication device 54 clamped to exterior of the tubing 12. The wireless power and communication device 54 may be for example, electromagnetic induction coils, and may be positioned at approximately same depth as the flexible sensor module 50C. The sensor module 50C is itself provided with a device, e.g., electromagnetic induction coils, that communicate with and obtain electric power from the wireless power and communication device 54. In some embodiments, the sensor module 50C may have an electric power supply built in, as for example one or several batteries, where providing electrical power through the power and communication device 54 is not practical. In some embodiments, a data receiver module may be mounted into or onto the wellhead (not shown), where also commands from such receiver module may be communicated to the wireless power and communication device 54, and ultimately to the flexible sensor module 50C.

[0064] FIG. 16 illustrates another embodiment of a self-drilling semi-flexible sensor module 50 placed on a sub which may be attached to the exterior of the tubing 12. Other components of the well shown in FIG. 16 may be similar to those shown in and explained with reference to FIG. 1. The module 50 may be disposed in a shaped side pocket 60 on the exterior of the tubing 12 such that longitudinal movement of the module will cause it to be axially deflected toward the first casing string 14. The module 50 may comprise a drill-bit 50D with integral seal, a motor 50E to rotate the drill bit 50D, and a pressure sensor and associated signal processing and communication electronics 50F. Power and communication can be supplied by a cable, or may be provided internally such as by batteries.

[0065] FIG. 17 shows the module 50 having drilled an opening 14A through the first casing string 14 such that fluid communication with the B annulus is established. A seal associated with the drill-bit 50D will ensure pressure isolation between the B annulus 20 and the A annulus. An internal passage (not shown separately) inside the module 50 communicates fluid pressure in the B annulus 20 to the pressure transducer 50C such that pressure in the B annulus 20 may be measured and such measurements communicated to the surface.

[0066] FIG. 18 shows a cross-sectional view of the module 50 attached to the tubing 12 by the side pocket 60. Although the embodiment shown in FIGS. 16 through 18 has the module 50 oriented so that it moves upwardly, it will be appreciated by those skilled in the art that a downwardly moving module is within the scope of the present disclosure.

[0067] FIG. 19 illustrates a plug 70 installed in the wall of a well tubular such as the tubing 12 in such a way that the tubing 12 and the first casing string 14 are forced apart, allowing for more space in the A annulus 18 for installation of various plugs, valves and measurement devices. The principle of tubular axial separation shown in FIG. 19 may apply equally to axial separation of the first casing string 14 and the second casing (16 in FIG. 1) such that the size of the B annulus (20 in FIG. 1) is increased. A plug 70 as shown herein may be, for example, a threaded bolt installed in an opening made by a tool such as the one described in US Patent No. 10,370,919 issued to Hansen et al.

[0068] In light of the principles and example embodiments described and illustrated herein, it will be recognized that the example embodiments can be modified in arrangement and detail without departing from such principles. The foregoing discussion has focused on specific embodiments, but other configurations are also contemplated. In particular, even though expressions such as in “an embodiment," or the like are used herein, these phrases are meant to generally reference embodiment possibilities, and are not intended to limit the disclosure to particular embodiment configurations. As used herein, these terms may reference the same or different embodiments that are combinable into other embodiments. As a rule, any embodiment referenced herein is freely combinable with any one or more of the other embodiments referenced herein, and any number of features of different embodiments are combinable with one another, unless indicated otherwise. Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.