Method and apparatus for suspending a well

Abstract

A method is for suspending flow in a well. The method includes placing a first plug in a production tubular in an upper wellhead section, above a downhole safety valve. The first plug is adapted to fit into the production tubular to form a fluid seal in the production tubular to form a barrier for containing well fluid; equipped with instrumentation for obtaining information by measuring physical characteristics below the plug; and equipped with means for transmitting said obtained information to an operator. There is also described an apparatus for suspending flow in the well.

Claims

1. A method of suspending flow of a well fluid in a well, wherein the well is completed, the method comprising: providing a production tubular in an upper wellhead section; providing a downhole safety valve in an opened position in the production tubular, wherein the opened position permits the flow of the well fluid during a producing phase of the well; providing a production master valve in the opened position in the production tubular upstream of the downhole safety valve, wherein the downhole safety valve and the production master valve define a shallow region of the production tubular; actuating the downhole safety valve from the opened position to a closed position such that flow of the well fluid through the downhole safety valve is arrested; placing a first plug in the shallow region of the production tubular by passing the first plug through the production master valve, wherein the first plug is: adapted to directly contact the production tubular to form a barrier for containing the well fluid; equipped with instrumentation for obtaining information by measuring physical characteristics below the first plug; and equipped with means for transmitting said obtained information to an operator.

2. The method according to claim 1, wherein the well is a producing well.

3. The method according to claim 1, wherein the method further comprises the step of obtaining information on the characteristics of a fluid in the well by use of the instrumentation for obtaining information of the first plug.

4. The method according to claim 3, wherein the step of obtaining information on the characteristics of a fluid in the well comprises the step of obtaining information on the characteristics of a fluid in a chamber of the well below the first plug, and in a chamber of the well above the first plug.

5. The method according to claim 1, wherein the method further comprises setting a second plug above the first plug.

6. The method according to claim 5, wherein the second plug is equipped with instrumentation for obtaining information by measuring physical characteristics below and above the second plug; and equipped with means for transmitting said obtained information to an operator.

7. The method according to claim 1, wherein the method further comprises the step of obtaining information on the characteristics of a fluid in a chamber of the well between the first plug and the second plug and above the second plug by use of the instrumentation for obtaining information of the second plug.

8. The method according to claim 1, wherein the method comprises the step of transferring information to and from the first plug and the second plug from and to an operator.

9. The method according to claim 1, wherein the method comprises the step of connecting a lubricator to the well, and wherein the step of placing a first plug in the production tubular comprises the step of using the lubricator to place the first plug in the well.

10. The method according to claim 1, wherein the first plug is the first plug to be set as part of the method of suspending flow in the well.

11. A method of suspending flow in a petroleum producing well, wherein the method comprises: placing at least one plug in a production tubular in an upper wellhead section above a downhole safety valve that is located in the production tubular and through which well fluids flow during a producing phase of the well, wherein the at least one plug comprises: a nose section; an instrument section coupled to an upstream end of the nose section, wherein the instrument section comprises a plurality of locking devices configured to extend radially outwardly from the instrument section and directly intrude into the production tubular to lock a position of the plug, and wherein the instrument section is equipped with instrumentation for measuring physical characteristics below the plug and means for transmitting such information to an operator and wherein the at least one plug forms part of a secondary barrier containing the well fluids; and a plug section coupled to an upstream end of the instrument section, wherein the plug section comprises at least one seal member configured to directly contact the production tubular to form a barrier for containing well fluid; communicating with the plug instrumentation using a control unit located inside or outside of the production tubular and making the information transmitted from the plug available to an operator.

12. The method according to claim 11 where a second plug is set in the tubular above the first plug and where the first plug forms part of a primary barrier and where the second plug forms part of a secondary barrier containing the well fluids.

13. The method according to claim 11 where the method of transferring information from the plug to or from an operator is by means of acoustic signaling.

14. The method according to claim 11 where the method of transferring information from a plug to or from an operator is by means of electromagnetic signaling.

15. The method according to claim 11 where communication between a control unit (A) and a plug is achieved by the control unit (A), or part of a control unit being lowered into the well inside the tubular.

16. The method according to claim 11 where the physical characteristics include fluid pressure.

17. The method according to claim 11 where the physical characteristics includes fluid temperature.

18. The method according to claim 11 where the physical characteristics includes fluid type determined by fluid density, viscosity, pH, conductivity, resistivity or refractive index.

19. The method according to claim 11 where the method of setting and retrieving the first plug and the secondary plug is by use of a lubricator tool.

20. The method according to claim 12, where the first plug and the second plug are mechanically connected allowing setting or retrieval of both plugs in a single well entry operation.

21. An apparatus for suspending flow in a well, the apparatus comprising: a first plug and a second plug, each comprising: a nose section; an instrument section coupled to an upstream end of the nose section; wherein the instrument section comprises a plurality of locking devices configured to extend radially outwardly from the instrument section and directly intrude into a production tubular to lock a position of the plug, and wherein the instrument section is equipped with instrumentation for obtaining information by measuring physical characteristics in theft well and means for transmitting said information to an operator; and a plug section coupled to an upstream end of the instrument section, wherein the plug section comprises at least one seal member configured to directly contact the production tubular to form a barrier for containing well fluid; a cylindrical connector member that couples the first plug to the second plug and allows setting or retrieval of both plugs in a single well entry operation; wherein the instrumentation of at least one of the first plug or the second plug is configured to measure physical characteristics of the well in a sealed region surrounding the cylindrical connector between the first plug and the second plug.

22. The apparatus according to claim 21, wherein the instrumentation for obtaining information by measuring physical characteristics of the first plug and the second plug comprise instrumentation for obtaining information by measuring physical characteristics below the plug in operational use.

23. The apparatus according to claim 21, wherein the cylindrical connector member has a smaller diameter than the first plug and the second plug, such that the cylindrical connector member defines a chamber in the well between the first plug and the second plug when the apparatus is in operational use.

24. The apparatus according to claim 21, wherein the first plug and the second plug are mechanical tubular plugs.

25. The apparatus according to claim 21, wherein the first plug and the second plug comprises instrumentation for receiving a command from an operator and configured to be actuated upon receiving a command from the operator.

Description

DESCRIPTION AND DRAWINGS

(1) There will now be described, by way of example only, embodiments of the invention, with reference to the accompanying drawings, in which:

(2) FIG. 1 shows a schematic representation of a production well in producing mode;

(3) FIG. 2 shows a schematic representation of the production well having been suspended by setting a deep-set plug below a downhole safety valve and a shallow-set plug above the downhole safety valve, in accordance with prior art;

(4) FIG. 3 shows a schematic representation of the production well having been suspended by closing a downhole safety valve and by setting a shallow-set plug above the downhole safety valve;

(5) FIG. 4 shows a schematic representation of the production well having been suspended by closing the downhole safety valve, setting a first shallow-set plug above the downhole safety valve, and setting a second shallow-set plug above the first plug;

(6) FIG. 5 shows a schematic representation of the production well prepared for wireline intervention;

(7) FIG. 6 shows a schematic representation of the production well prepared for lubricator intervention;

(8) FIG. 7a illustrates an embodiment of a plug set in a production tubular of a well;

(9) FIG. 7b illustrates another embodiment of a plug set in a production tubular of a well;

(10) FIG. 7c illustrates an embodiment of a tandem plug set in a production tubular of a well; and

(11) FIG. 7d illustrates another embodiment of a tandem plug set in a production tubular of a well.

(12) FIG. 1 shows a production well (1) in producing mode where there is fluidic connection between the hydrocarbon producing formation (F) and the outlet from a production master valve (2.sub.3). The well (1) comprises a downhole safety valve (4.sub.0), a manual master valve (2.sub.5), a hydraulic master valve (2.sub.4) and the production master valve (2.sub.3) that are all in an open position in this mode. The open valves allow for free flow of formation fluid from the formation (F), through the production tubular perforations, through a production tubular (3.sub.1) of the well (1), and through the open valves, to production. Furthermore, the well comprises a kill valve (2.sub.2) and a swab valve (2.sub.1) that are closed when the well (1) is in production mode.

(13) The well (1) further comprises a wellhead (3.sub.0), equipped with a Christmas tree (2.sub.0). The Christmas tree (2.sub.0) comprises the production master valve (2.sub.3), hydraulic master valve (2.sub.4) and manual master valve (2.sub.5), and allows for closing production by closing one or more of said valves. The Christmas tree (2.sub.0) further comprises the kill valve (2.sub.2), and the swab valve (2.sub.1). Production can also be interrupted by opening the kill valve (2.sub.2) to divert flow of produced fluid from the formation (F) through the kill valve (2.sub.2). The swab valve (2.sub.1) allows for introduction of intervention equipment, e.g. for well suspension or reworking.

(14) The production well (1) extends from the wellhead (3.sub.0) or, if mounted, the Christmas tree (2.sub.0), down to the producing formation (F) through a production tubular (3.sub.1) which at the hydrocarbon bearing formation (F) is perforated (P) to allow inflow of well fluids. The production tubular (3.sub.1) is contained within several casings (3.sub.2). The casings (3.sub.2) form annular volumes (V.sub.A, V.sub.B and V.sub.C) extending from the wellhead (3.sub.0) to casing shoes (3.sub.6) that are sealed towards the surrounding formation or to casing packers (3.sub.7) that are sealed towards the production tubular (3.sub.1) and cemented (C) towards the surrounding formation. Each annular volume (V.sub.A, V.sub.B and V.sub.C) is contained by annulus valves (3.sub.3, 3.sub.4, and 3.sub.5).

(15) The downhole safety valve (4.sub.0) and an annular safety valve (5.sub.0) are arranged in the production tubular. The annular safety valve (5.sub.0) is arranged to close the annulus formed between the production tubular (3.sub.1) and the innermost casing (3.sub.2).

(16) The production well (1) elements form two barriers isolating the formation (F) fluids from the surrounding environment (E). A primary barrier (P.sub.B) is formed by the formation (F), cement (C), production tubular (3.sub.1), packers (3.sub.7) and downhole safety valve (4.sub.0). A secondary barrier (S.sub.B) is formed by the primary barrier (P.sub.B), casing (3.sub.2), cemented casing shoe (3.sub.6), annular safety valve (5.sub.0), wellhead (3.sub.0) and Christmas tree (2.sub.0) valves (2.sub.1, 2.sub.2, 2.sub.3, 2.sub.4, and 2.sub.5).

(17) FIG. 2 shows the production well (1) having been suspended by setting a deep-set first plug (6.sub.0) below the downhole safety valve (4.sub.0), closing the downhole safety valve (4.sub.0) and setting a shallow-set second plug (7.sub.0) in the upper wellhead section above the downhole safety valve (4.sub.0). Furthermore, in this mode, the production master valve (2.sub.3), the hydraulic master valve (2.sub.4) and the manual master valve (2.sub.5) are all closed. Setting a deep plug requires intervention equipment capable of deep entry into the well, such as a wireline unit, a coiled tubing unit or drill pipe. By suspending the well in this manner, only a small section of the well, a first chamber (V.sub.WH-P2) between the second plug and the manual master valve (2.sub.5) can typically be monitored. However, it may also be possible by use of a downhole pressure gauge or tubing-to-annulus communication to provide a pressure reading of a second chamber (V.sub.DHSV-P1) of the well (1), between the deep-set first plug (6.sub.0) and the downhole safety valve.

(18) FIG. 3 shows the production well (1) having been suspended according to the invention by closing the downhole safety valve (4.sub.0) and setting a shallow-set first plug (6.sub.0) above the downhole safety valve (4.sub.0), in addition to closing the production master valve (2.sub.3), the hydraulic master valve (2.sub.4) and the manual master valve (2.sub.5). The first plug (6.sub.0) is instrumented and has instrumentation for obtaining information by measuring physical characteristics below the plug (not shown) and means for transmitting said obtained information to an operator (not shown). By use of the instrumentation of the first plug (6.sub.0), a third chamber (V.sub.P1-DHSV), between the first plug (6.sub.0) and the downhole safety valve (4.sub.0), can be monitored, in addition to a first chamber (V.sub.WH-P1), between the first plug (6.sub.0) and the manual master valve (2.sub.5), and a fourth chamber (V.sub.DHSV-F) between the downhole safety valve (4.sub.0) and the formation (F). Monitoring of the fourth chamber (V.sub.DHSV-F) is made possible by use of a downhole pressure gauge (not shown) or tubing-to-annulus communication, or through metering below the first plug (6.sub.0) through normal static condition leakage through the closed downhole safety valve (4.sub.0).

(19) FIG. 4 shows the production well (1) having been suspended according to the invention by closing the downhole safety valve (4.sub.0), setting a shallow-set first plug (6.sub.0) above the downhole safety valve (4.sub.0), and setting a shallow-set second plug (7.sub.0) above the first plug (6.sub.0). In addition, the production master valve (2.sub.3), the hydraulic master valve (2.sub.4) and the manual master valve (2.sub.5) have been closed. Setting a shallow plug may be done by use of a lubricator tool. In this embodiment, the monitored chambers (M) include the first chamber (V.sub.WH-P2) between the second plug (7.sub.0) and the manual master valve (2.sub.5), a fifth chamber (V.sub.P2-P1) between the second plug (7.sub.0) and the first plug (6.sub.0), the third chamber (V.sub.P1-DHSV) between the first plug (6.sub.0) and the downhole safety valve (4.sub.0), and the fourth chamber (V.sub.DHSV-F) between the downhole safety valve (4.sub.0) and the formation (F). The first chamber (V.sub.WH-P2) and the fifth chamber (V.sub.P2-P1) are monitored using instrumentation (not shown) included in the second plug (7.sub.0), the third chamber (V.sub.P1-DHSV) is monitored using instrumentation (not shown) included in the first plug (6.sub.0), and the fourth chamber is monitored by use of a downhole pressure gauge (not shown).

(20) FIG. 5 shows the production well (1) prepared for wireline (8.sub.0) intervention. The primary barrier (P.sub.B) is maintained while the downhole safety valve (4.sub.0) remains in a closed position. The secondary barrier (S.sub.B) is maintained with the swab valve (2.sub.1) in a closed position, or with the swab valve (2.sub.1) in an open position when the wireline unit (8.sub.0) forms part of the secondary barrier (S.sub.B) envelope following a pressure test.

(21) FIG. 6 shows the production well (1) prepared for lubricator tool (9.sub.0) intervention. The primary barrier (P.sub.B) is maintained while the downhole safety valve (4.sub.0) remains in a closed position. The secondary barrier (S.sub.B) is maintained with the swab valve (2.sub.1) in a closed position, or with the swab valve (2.sub.1) in an open position when the lubricator tool (9.sub.0) forms part of the secondary barrier (S.sub.B) envelope following a pressure test.

(22) FIG. 7a shows a mechanical plug (10.sub.0) with two seals (10.sub.1), which when actuated, seals and separates the volume of the production tubular (3.sub.1) above the plug (10.sub.0) from that which is below the plug (10.sub.0). The plug (10.sub.0) may be mechanically locked in its position by means of a locking device (10.sub.2) which may intrude into the production tubular (3.sub.1) or equivalent devices designed to fit into a groove in the production tubular (3.sub.1). Such a mechanical plug (10.sub.0) may have multiple sealing elements sealing and separating the volume of the production tubular (3.sub.1) above the plug (10.sub.0) from that which is below the plug (10.sub.0).

(23) The mechanical plug (10.sub.0) is also equipped with an instrument section (10.sub.4) which in this example has been adapted to fit between the mechanical plug's (10.sub.0) main body and its bull nose (10.sub.3) mounted at its lower end. The instrument section (10.sub.4) may have fluid connection with borehole chambers above and/or below the plug (10.sub.0) and may form the pressure retaining element of the plug (10.sub.0), separating the two chambers. The instrument section (10.sub.4) may contain instrumentation for obtaining information by measuring physical characteristics in a fluid above and/or a fluid below the plug (10.sub.0) such as pressure, temperature, density etc. and means of transmitting said information by use of commonly known methods such as transmitting information acoustically through a tubular wall, transmitting information electromagnetically etc. from within the borehole to a location within or outside of the borehole and made available to an operator. The information may typically include pressure above the plug (P.sub.2), temperature above the plug (T.sub.2), pressure below the plug (P.sub.1), temperature below the plug (T.sub.1) and physical characteristics such as density (ρ.sub.1) or other characteristics allowing determination of fluid type (gas, crude oil, brine, water etc.) and if plural (ρ.sub.1, ρ.sub.2 or more) allowing determination of rate of change (Q.sub.1) (cm.sup.3/min) and thus flow/inflow. The following plugs from preceding figures are of this type: FIG. 3—plug (6.sub.0) and FIG. 4—plug (6.sub.0).

(24) FIG. 7b shows a mechanical plug (11) with seals (11.sub.1), which when actuated, seals and separates a chamber of the production tubular (3.sub.1) above the plug from a chamber below the plug (11.sub.0). The plug (11.sub.0) may be mechanically locked in its position by means of a locking device (11.sub.2) which may intrude into the production tubular (3.sub.1) or equivalent devices designed to fit into a groove in the production tubular (3.sub.1). The following plugs from preceding figures may be of this type: FIG. 2—plug (6.sub.0) and plug (7.sub.0), FIG. 4—plug (7.sub.0).

(25) FIG. 7c shows a mechanical plug assembly (12.sub.0) with one locking device (12.sub.4), a first sealing body (12.sub.1) and a second sealing body (12.sub.2), each with seals (12.sub.3). When the seals of the sealing bodies (12.sub.1, 12.sub.2) are actuated, they seal and separate a chamber in the production tubular (3.sub.1) above the first sealing body (12.sub.1) from a chamber in the production tubular (3.sub.1) below the first sealing body (12.sub.1), and a chamber of the production tubular (3.sub.1) below the second sealing body (12.sub.2) from a chamber of the production tubular (3.sub.1) above the second sealing body (12.sub.2), and forms an enclosed chamber between the first sealing body (12.sub.1) and the second sealing body (12.sub.2). Each of the chambers may be monitored by instrumentation (12.sub.6) included in the plug assembly (12.sub.0). The plug assembly (12.sub.0) is made such that it may be set in a single run.

(26) FIG. 7d Illustrates a second embodiment of the mechanical plug assembly (13.sub.0) with a first locking device (13.sub.4) and a second locking device (13.sub.5) and a first sealing body (13.sub.1) and a second sealing body (13.sub.2). Each sealing body (13.sub.1, 13.sub.2) comprises seals (13.sub.3). When actuated, the seals of the first sealing body (13.sub.1) seal and separate a chamber of the production tubular (3.sub.1) above the first sealing body (13.sub.1) from a chamber of the production tubular (3.sub.1), and the seals of the second sealing body (13.sub.2) seal and separate a chamber of the production tubular (3.sub.1) below the second sealing body (13.sub.2) from a chamber of the production tubular (3.sub.1) above the second sealing body (13.sub.2). The sealing bodies (13.sub.1, 13.sub.2) further forms a chamber between the upper sealing body (13.sub.1) and the lower sealing body (13.sub.2). Each of the volumes, above the upper sealing body (13.sub.1), below the lower sealing body (13.sub.2) and between the sealing bodies (13.sub.1) and (13.sub.2) may be monitored by instrumentation (13.sub.6) included in the plug assembly (13.sub.0). The mechanical plug assembly (13.sub.0) is arranged with a mechanical connection (13.sub.8) connecting the first sealing body (13.sub.1) and first locking device (13.sub.4) with the second sealing body (13.sub.2) and second locking device (13.sub.5). The plug assembly is made such that it may activate both locking devices (13.sub.4, 13.sub.5) and all seals (13.sub.3) in a single run.

(27) The plug (10.sub.0) shown in FIG. 7a and the plug assemblies (12.sub.0, 13.sub.0) shown in FIG. 7c and in FIG. 7d are possible embodiments of the apparatus according to the second aspect of the invention. The plug assemblies shown in FIG. 7c and in FIG. 7d may be referred to as tandem plugs.

(28) For both a lubricator tool and a wireline unit the top of the lubricator assembly includes high-pressure grease-injection section and sealing elements. The lubricator is installed on top of the Christmas tree and tested, the plug is placed in the lubricator and the lubricator is pressurized to wellbore pressure. Then the top valves of the Christmas tree are opened to enable the plug to be guided mechanically, to fall or to be pumped into the wellbore under pressure. To remove the tools, the reverse process is used: the plug is pulled up into the lubricator under wellbore pressure, the Christmas tree valves are closed, the lubricator pressure is bled off, and the lubricator may be opened to remove the plug.

(29) FIG. 1 shows a well (1) in normal production mode. FIG. 2 shows the same well (1) suspended according to methodology known from prior art. The deep-set first plug (6.sub.0) and the shallow-set second plug (7.sub.0) in FIG. 2 are placed by use of a wireline unit (8.sub.0), such as illustrated in FIG. 5, while the kill valve (2.sub.2) and the production master valve (2.sub.3) are closed and the swab valve (2.sub.1), the hydraulic master valve (2.sub.4), the manual master valve (2.sub.5) and the downhole safety valve (4.sub.0) are open, as required for lowering/hoisting the wireline and connected tools/plugs.

(30) In a first embodiment the invention relates to a method of suspending a production well (1) different from prior art practice in the petroleum industry which involves setting a deep-set plug (6.sub.0) and a shallow-set plug (7.sub.0) as illustrated in FIG. 2, and instead setting a shallow-set plug (6.sub.0) as illustrated in FIG. 3 arranged with instrumentation to sufficiently monitor fluid characteristics in chambers of the production tubular (3.sub.1) above the plug (V.sub.WH-P1) and below the plug (V.sub.P1-DHSV) extending to the downhole safety valve (4.sub.0). In this embodiment the downhole safety valve (4.sub.0) forms part of the primary barrier (P.sub.B) and the plug (6.sub.0) forms part of the secondary barrier (S.sub.B).

(31) In a second embodiment, shown in FIG. 4, the method according to the invention involves suspending the well (1) by use of a first shallow-set plug (6.sub.0) and a second shallow-set plug (7.sub.0) incorporating sufficient instrumentation to measure physical characteristics in chambers (V.sub.P2-P1, V.sub.P1-DHSV) in the production tubular (3.sub.1). In this embodiment the downhole safety valve (4.sub.0) and the first plug (6.sub.0) form part of the primary barrier (P.sub.B) and the second plug (7.sub.0) forms part of the secondary barrier (S.sub.B).

(32) In both embodiments of the method according to the first aspect of the invention, the statutory barrier requirements are fulfilled, however the first embodiment depends upon the quality and state of the downhole safety valve (4.sub.0) and presence of pressure status monitoring of the volume below the downhole safety valve (4.sub.0). In the second embodiment the downhole safety valve (4.sub.0) supported by the first plug (6.sub.0) form the primary barrier (P.sub.B) and provides as a minimum pressure monitoring of the chamber (V.sub.P1-DHSV) below the downhole safety valve (4.sub.0).

(33) The first chamber (V.sub.WH-P1) in FIG. 3 and the first chamber (V.sub.WH-P2) in FIG. 2 and FIG. 4, above the uppermost plug, may otherwise usually be monitored by Christmas tree-mounted instrumentation. The second chamber (V.sub.DHSV-P1) in FIG. 2, the fourth chamber (V.sub.DHSV-F) in FIG. 3 and FIG. 4, below the downhole safety valve (40), may be monitored by a downhole gauge if installed, or by static monitoring through leakage across the downhole safety valve (4.sub.0).

(34) In both the first and the second embodiments as illustrated in FIGS. 3, 4 and 5 the plug (6.sub.0) or plugs (6.sub.0, 7.sub.0) may be set and retrieved by use of a lubricator tool (9.sub.0) such as illustrated in FIG. 6. When pressure tested and connected to the Christmas tree (2.sub.0) the lubricator tool (9.sub.0) may form part of the secondary barrier (S.sub.B). As neither the first or second embodiment require opening of the downhole safety valve (4.sub.0) it is possible to maintain a primary barrier (P.sub.B) and a secondary barrier (S.sub.B) at all times during well suspension operations leading to further enhanced safety versus conventional suspension.

(35) In both embodiments the first plug (6.sub.0) is instrumented such as illustrated in FIG. 7a (10.sub.0) enabling measurement of pressure (P.sub.2) and temperature (T.sub.2) above the plug (10.sub.0) and pressure (P.sub.1), temperature (T.sub.1) and density (ρ.sub.1) below the plug. The plug (10.sub.0) is equipped with a locking device (10.sub.2) which mechanically locks the plug (10.sub.0) to the tubular (3.sub.1). The locking may take form of teeth in the locking device (10.sub.2) intruding into the tubular (3.sub.1) wall, or take form of a profile which enters into an equivalent groove in the tubular or wellhead. The plug (10.sub.0) is equipped with seals (10.sub.1) which seal the void between the plug (10.sub.0) and the tubular (3.sub.1) when activated.

(36) The second plug (7.sub.0) may be a non-instrumented plug such as illustrated in FIG. 7b (11.sub.0). However, both plugs may be instrumented allowing metering of physical characteristics above, below and/or between the plugs (60, 70), in any relevant combination.

(37) The instrumented plug (10.sub.0) in FIG. 7a, or the first plug (6.sub.0) in FIGS. 3 and 4, contains an instrument section which may be removable and adapted to most types of plugs without mechanical reworking, e.g. by removing the bullnose (10.sub.3), attaching the instrument section (10.sub.4) to the plug (10.sub.0) in place of the bullnose (10.sub.3) and, if needed, reattaching the bullnose (10.sub.3) to the instrument section (10.sub.4) thereby obtaining a similar but elongated version of a non-instrumented plug (11.sub.0).

(38) The instrument section (10.sub.4) may contain energy storage devices, logic processing units, electronic circuitry and arrangements for transmitting and/or receiving data to/from an opposite control unit (A) located inside or outside the production tubular (3.sub.1), or outside the well in the surrounding environment (E). Data may be transmitted, in one or both directions and an operator may transmit a command initiating a specific action, conversely the plug (10.sub.0) may be equipped with actuation devices such as valves, perforation charges etc. which may be actuated from the control unit (A).

(39) Communication may be acoustic or electromagnetic or by any other means of communication such as disclosed in general literature and in other patents and will not be further discussed herein.

(40) When using plugs (10.sub.0, 11.sub.0) such as illustrated in FIGS. 7a and 7b each plug (10.sub.0, 11.sub.0) needs to be set in a separate run. I.e. a lower plug (10.sub.0, 11.sub.0) must be set in place, thereafter the tool used to set the plug (10.sub.0, 11.sub.0) must be retracted and connected to the upper plug (10.sub.0, 11.sub.0) before setting this, meaning that two separate tool runs are required.

(41) Equal barrier protection and functionality may be achieved by use of special plugs with one or more barriers or one or more plugs mechanically connected each with one or more barriers, in any relevant combination with each other or with plugs (10.sub.0, 11.sub.0) as illustrated in FIGS. 7a and 7b.

(42) The plugs (10.sub.0, 11.sub.0, 12.sub.0, 13.sub.0) as described may find use in other applications and shall not be limited by the method described herein.