WELL ABANDONMENT AND SLOT RECOVERY

The present invention relates to methods and apparatus for well abandonment and slot recovery and in particular, though not exclusively, to a method and apparatus for removing control lines in a well bore during a well abandonment and slot recovery procedure.

When a well has reached the end of its commercial life, the well is abandoned according to strict regulations in order to prevent fluids escaping from the well on a permanent basis. In meeting the regulations it has become good practise to create the cement plug over a predetermined length of the well. In order to achieve this, the production tubing and control lines attached thereto are typically first removed Cement can then be inserted in casing annulus and between the outermost casing and the formation. Alternatively casing is removed to access the formation or the outermost casing section, on which a cement bond log has been performed to verify the cement bond between the outermost casing and the formation, prior to placing cement to create a plug within the well bore.

These operations require a rig which makes them very expensive for abandonment in subsea wells. Consequently, so-called 'rig-less' methods of well abandonment are being developed. These either fall into designing systems to operate from floating vessels which attempt to carry out the same procedures or look at ways to create the cement plug without removing the casing and/or production tubing. A major difficulty in leaving the production tubing in place is in the handling of control lines in the well. In abandoning a well, control lines cannot simply be cemented in place as they present a potential leak path through the cement plug. Additionally, if the production tubing is removed care must be taken to ensure that control lines are successfully removed to ensure no line is left in the well bore. This can occur as cutting blades may merely push the line out of the path of the blade when the line is not fixed to the outside of the production tubing at the cutting position. The act of pulling the tubing from the well will likely cause the control line to stretch and break at some undetermined location leaving a length of loose control line in the annulus. Unless the breakage point is known, the loose control line needs to be retrieved in a costly fishing exercise as any cement placed in the annulus with the control line present will present a potential leak path.

US2014/0326470 describes a well completion arrangement and method for removing at least a portion of a line running in an annulus between tubing and a casing in a well. The arrangement comprises at least two clamping means spaced apart in the longitudinal direction of the tubing and fixed thereto, the clamping means being configured for fixing the line with respect to tubing, a splitting means for releasing the line from the interval defined by at least an upper clamping means and a lower clamping means of the at least two clamping means, a line manipulator apparatus for activating said release of the line, and a line retrieval apparatus for displacing into the tubing the portion of the line from said interval, thereby removing the line from the annulus. While this arrangement allows for removal of a control line without removal of the production tubing and determines the location of separation, the invention must be in place when the completion is run in the well. Unfortunately this does not provide a solution for older wells which include standard completions.

It is therefore an object of the present invention to provide a method for removing one or more control lines in a well during a well abandonment procedure which obviates or mitigates at least some of the advantages of the prior art.

It is a further object of the present invention to provide a method for removing one or more control lines in a well during a well abandonment procedure which ensures that the control lines are severed and determines the location of separation.

According to a first aspect of the present invention there is provided a method for removing one or more control lines in a well, the control lines running in an annulus behind a tubular in the wellbore, during a well abandonment procedure comprising the steps:

(a) perforating the tubular at a location adjacent the one or more control lines;

(b) displacing a self-supporting settable composition through the perforations into the annulus to secure the one or more control lines in place;

(c) cutting the tubular and the one or more control lines at the location of the self-supporting settable composition ;

(d) washing away the self-supporting settable composition; and

(e) removing at least a portion of the one or more control lines from the wellbore.

In this way, by securing the control lines to the tubular being cut we can ensure that the control lines will also be cut throug h.

Here we consider control lines to be any line running in an annulus behind a tubular in the wellbore. Such a line may be a tool control line, a communication line, a chemical injection line or the like. The line may be used to transmit electric or fiber-optic signals, electric power, hydraulic fluid, scale inhibiting chemicals and similar. The annulus may be between a tubular, such as casing, and the wellbore wall at the formation. Preferably the annulus is between two tubulars. More preferably, the one or more control lines are arranged in the annulus between the production tubing and casing.

The self-supporting settable composition may be a resin. The self- supporting settable composition may be a gel. In an embodiment, the self-supporting settable composition is a Thermatek™ rigid setting fluid available from Halliburton Corporation, USA. The method may comprise deploying an injection tool to displace a pre-determined amount of self- supporting settable composition through the perforations into the annulus.

The method may include displacing the self-supporting settable composition into the annulus as a foam. In this way, fluids which are typically not self-supporting may be arranged to be so.

The method may comprise running a perforating tool through the tubular to a predetermined and/or desired depth.

The method may comprise perforating the tubular using explosive charges or a perforating tool. The method may comprise perforating the tubular using a tubing punch. The method may comprise providing a tubing cutter to cut a circumferential slot through a wall of the tubular to sever the tubular and the one or more control lines. The method may then comprise pulling the cut section of tubular with the severed one or more control lines attached from the well. This could be done using a rig.

The method may comprise deploying a milling tool to mill away a longitudinal section of the tubular and the corresponding portion of the one or more control lines. The method may comprise milling in an upward or downward direction. The method may comprise milling away the tubular up to the top of the self-supporting settable composition. This allows abandonment to be performed without having to pull the tubular and thus a rigless well abandonment operation can be achieved.

The method may comprise soaking the set self-supporting settable composition as part of the washing step. The method may comprise using an acid wash to remove the set self-supporting settable composition.

The method may comprise washing the annulus prior to displacing self- supporting settable composition. This may help the self-supporting settable composition to adhere to the walls of the tubular(s). The method may comprise performing a cement bond log on an exposed outer tubular bounding the annulus. The method may further comprise deploying a cement plug to set against the exposed outer tubular. Thus the method can be used to form a cement plug in well abandonment if the cement bond is of good quality.

The method may comprise repeating the steps at a shallower depth in the wellbore. This may be needed if the tubular and one or more control lines are stuck and cannot be pulled or if, following milling, the CBL finds the cement bond to be of poor quality.

Preferably, the steps (a) to (e) are performed in order. The steps may be performed on separate trips into the well. Alternatively two or more steps may be performed on the same trip into the well. In the description that follows, the drawings are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results.

Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Use of terms such as "upper" and "lower" are considered relative and though the well bore is drawn in the ideal vertical orientation, it will be appreciated that this may be deviated. Language such as "including," "comprising," "having," "containing," or "involving," and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term "comprising" is considered synonymous with the terms "including" or "containing" for applicable legal purposes.

All numerical values in this disclosure are understood as being modified by "about". All singular forms of elements, or any other components described herein including (without limitations) components of the apparatus are understood to include plural forms thereof.

There will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which:

Figure 1 shows a sectional diagram of a typical well with two strings of casing, production tubing and a control line installed.

Figures 2a to 2f show sectional diagrams of a well demonstrating the typical sequence of operations to remove a portion of a control line from a well in a well abandonment method according to an embodiment of the present invention;

Figures 3a to 3h show sectional diagrams of a well demonstrating the typical sequence of operations to remove a portion of a control line from a well in a well abandonment method according to a further embodiment of the present invention;

Figures 4 to 6 shows sectional diagrams of a well demonstrating the typical sequence of operations to assess the condition of a cement bond at a zone according to a still further embodiment of the invention; and

Figure 7a and 7b shows sectional diagrams of a well demonstrating the typical sequence of operations to assess the condition of a cement bond at further zone according to a yet further embodiment of the invention.

Reference is initially made to Figure 1 of the drawings which illustrates a portion of a typical well with two strings of casing and tubing installed. The upper section of wellbore 1 was drilled to a certain depth, after which casing 2 was run into the well. Cement 3 was set over a portion of the outside of the casing 2, sealing the annulus between the casing 2 and the wellbore 1. The next section of wellbore 4 was then drilled to the target depth of the well. A next section of casing 5 was run into the well, suspended inside the first casing 2 with a hanger 5a and likewise cemented 6 to seal the annulus between the second casing 5 and the wellbore 4. Production tubing 7 was then run into the wellbore and suspended at its upper end with a hanger 8 and anchored at its lower end by liner hanger system providing a packer 9. Below the packer 9, a production liner 10, was cemented 11 to a further section of wellbore 12. The liner 10 is open towards the hydrocarbon reservoir via perforations 13. The design and configuration of the production liner 10 may vary significantly from what is illustrated herein, however this will be appreciated by a person skilled in the art and not further described herein. The upper end 14 of the wellbore 1 is not shown, but those skilled in the art will appreciate that an upper completion would be present as would other components such as a sub-surface safety valve. For clarity, only parts required to describe the invention are illustrated.

In the production tubing 7 there may be located permanent downhole gauges 16 such would be required for measuring pressure and temperature. These gauges 16 are connected to and controlled from the surface via a control line 15. The control line 15 may be a single cable or a bundle of cables which are attached via couplings 17 to the production tubing 7 at intervals along its length. While the control line 15 is described as a gauge control line, it will be appreciated that the control line 15 may be any line running in an annulus 18 behind a tubular 7 in the wellbore 1,4,12. Such a line may be a tool control line, a communication line, a chemical injection line or the like. The line may be used to transmit electric or fiber-optic signals, electric power, hydraulic fluid, scale inhibiting chemicals and similar. When the time comes to abandon the well, in a first embodiment, the production tubing 7 is removed from the well. Figures 2a-f show a sequence of operations according to an embodiment of the present invention. The first operation is to perforate the tubing. In Fig. 2a, a perforating tool 19 is run through the tubing 7 to a first desired depth and explosive charges produce holes 20 in the tubing 7. The perforating tool 19 may alternatively punch holes 20 in the tubing 7. The length of the perforating tool 19 will determine the spacing of the holes 20 and the length of tubing 7 which is perforated. In Fig. 2b, an injection tool 22 deploys a pre-determined amount of a self-supporting settable composition 21, through the perforations 20 into the annulus 18 between the casing 5 and the tubing 7. In this exemplary embodiment, a fluid based on Thermatek™, a rigid setting fluid available from Halliburton Corporation, is used. The fluid 21 is injected as a foam through the perforations 20. By creating a foam from a fluid, gas is introduced to reduce the weight of the fluid and make it self-supporting. By self-supporting we mean that the composition 21 will remain in the annulus 18 in the area of the holes 20 and not fall down the annulus 18 via gravity. Preferably the composition 21 is designed to adhere to the walls of the tubing 7 and casing 5. Those skilled in the art will recognise other compositions such as gels and resins can also be used which are settable and self-supporting. Cement is considered to be non-self supporting. The injection tool 22 may include seals or packers 23a, b to assist in ensuring the composition enters the holes 20.

As the composition 21 enters the annulus 18 it will move around and cover the control line 15 effectively embedding it in the composition 21.

The composition 21 is then allowed to set hard, thus securing the tubing 7 and control line 15 rigidly in preparation for the next operations. The composition 21 is selected such that, when set, it provides a suitable compressive strength both to hold the tubing 7 and control lines 15 and be cut through without movement. In Fig. 2c, a tubing cutter 24 is deployed, cutting a slot 31 through the wall of the tubing 7 and through the control line 15. The blades 25 of the tubing cutter 24 are sized to extend across the annulus 18 to ensure that the control line 15 is cut. As the tubing 7 and control line 15 are fixed in position, the control line 15 cannot be pushed out of the way of the by the blades 25 and this ensures they are cut.

The production tubing 7 and control line 15 are now entirely severed at the slot 31. Thus the location of the point of cutting the control line 15 is known. The next step is to wash away the composition 21. This is typically done by locating a washing tool 26 over the holes 20 at the slot 31. A fluid capable of dissolving and/or dispersing the composition 21 is pumped through the holes 20 and slot 21. An acid wash is typically used with the composition 21 being acid soluble and permeable. This is illustrated in Fig. 2d.

With the composition 21 removed, the severed production tubing 7 can be pulled. The cut section of control line 15 will be pulled with the severed section of production tubing 7. This leaves a production tubing stub 27 with a control line 15 whose location is known and will not interfere with any operations carried out above the production tubing stub 27.

Casing 5 is now exposed and a cement bond log (CBL) can be performed using a cement bond logging tool 36 deployed through the tubing 7 to assess the quality of the cement 6 in the annulus 29 behind the casing 5. This is illustrated in Fig. 2e. If the cement is shown to be of adequate quality the next operation, as shown in Fig. 2f, is to run a bridge plug 28 and cementing tool (not shown) and create a cement plug 41 along a length of the casing 5 on which the cement bond quality in the annulus 29 has been verified. The bridge plug 28 is used to support the cement of the plug 41 while it sets. As the bridge plug 28 is set above the production tubing stubbing stub 27, there is no possibility of the control line 15 being present in the cement plug 41 and thus there can be no leaks through the cement plug 41 caused by a control line.

If desired, the method may include the additional step of performing a wash after the perforations have been made. This will clear away any debris and clean the walls of the tubing 7 and casing 5 so that the composition 21 may better adhere when displaced through the holes 20. Each step in the method described above may be performed as a separate trip into the well. Alternatively, any number of steps can be performed in a single trip by combining the respective tools on the work string. It will be recognised that the method may be used where the annulus is between a tubular and the borehole 1,4,12. In this arrangement the CBL is not required.

Additionally, if the tubular, once severed, cannot be pulled which may occur particularly when the tubular is production liner or casing, the method can be repeated at increasingly shallower depths in the well until a severed section of tubular can be removed.

Now referring to Figures 3a-h of the drawings there is shown a typical sequence of operations according to a further embodiment of the present invention and in particular show zone 2 in detail. The well is as shown in Figure 1, like parts have been given the same reference numeral to aid clarity. As for the first embodiment, the first operation is to perforate the tubing. In Fig. 3a, a perforating tool (not shown) is run through the tubing 7 to a first desired depth and explosive charges produce holes 20a in the tubing 7. The perforating tool (not shown) is moved to a second desired depth and explosive charges produce holes 20b in the tubing 7. Alternatively, the perforating tool can be moved along the tubing 17 to create holes 20 across the entire zone 2. Note that zone 2 can be at any position along the tubing 7 and does not have to be located at the packer 9 as in the prior art.

The next step is to wash the zone 2. A washing tool (not shown) is inserted through the tubing 7. The tool pumps a wash fluid through the perforations 20a, b while rubber cups both direct fluid through the holes 20a, b and wipe the wall 33 of the production tubing 7. The wash fluid removes dirt, debris and fines which may be in the annulus 18 over the zone 2 (see Fig. 3a). The wash fluid also cleans the wall of the tubing 7 and the casing 5 over the zone 2 which bound the annulus 18. This cleaning will assist in placement of the settable self-supporting composition 21 by ensuring that the annulus 18 is clear and that there are no materials on the walls which would prevent the composition 21 adhering to the walls.

In Fig. 3c, a downhole tool (not shown) deploys a pre-determined amount of a self-supporting settable composition 21, through the lower set of perforations 20b into the annulus 18 between the casing 5 and the tubing 7. In this embodiment, a fluid based on Thermatek™, a rigid setting fluid available from Halliburton Corporation, is used. The fluid 21 is injected as a foam through the perforations 20b and directed towards the upper perforations 20a. By creating a foam from a fluid, gas is introduced to reduce the weight of the fluid and make it self-supporting. By self- supporting we mean that the composition 21 will remain in the annulus 18 in the area of the holes 20 and not fall down the annulus 18 via gravity. Preferably the composition 21 is designed to adhere to the walls of the tubing 7 and casing 5. Those skilled in the art will recognise other compositions such as gels and resins can also be used which are settable and self-supporting. When the pre-determined amount of composition 21 has been deployed through the lower set of perforations 20b the level of composition 21 has reached the upper set of perforations 20a in the tubing 7. The downhole tool may have sensors to detect composition 21 coming back into the tubing 7 through the upper set of perforations 20a.

The composition 21 is then allowed to set hard, thus securing the tubing 7 and control line 15 rigidly in preparation for the next operations. The composition 21 is selected such that, when set, it provides a suitable compressive strength both to hold the tubing 7 and control lines 15 and be cut through without movement. In Fig 3d, a tubing cutter (not shown) is deployed, cutting a slot 31 through the wall of the tubing 7 and the control line 15, and Fig. 3e shows a tubing mill 35 deployed through, and milling away the tubing 7 and the control line 15 up to the top of the previously placed composition 21. Milling of the relatively weak-walled production tubing 7 and the control line 15 is possible by virtue of there being fixed rigidly in a solid composition 21. Thus a portion of the production tubing 7 and the control line 15 are removed from the wellbore.

The length of tubing 7 and control line 15 milled away is pre-planned and is labelled Ά' and might typically be 200ft. The tubing mill 35 is removed from the well. A layer 34 of set composition 21 may be left adhering on the wall of the casing 5 over the zone 2. This is removed by performing an acid wash. Acid may be circulated to soak through the composition 21 as described hereinbefore with reference to Fig. 2e. The acid dissolves the composition 21 and cleans the wall 33 of the casing 5 as illustrated in Fig. 3f. In this way any later applied cement will provide a good seal to the casing 5 which will limit the possibility of leak paths existing up the walls of the casing. Additionally, a better quality cement bond log will be obtained.

In Fig. 3g, a cement bond logging tool 36 is deployed through the tubing 7 to assess the quality of the cement 6 of zone 2. If the cement is shown to be of poor quality, then the well is suspended pending deployment of a rig to pull the tubing as per Figs. 2(e)-(f). Flowever, if the cement 6 is shown to be of adequate quality the next operation, as shown in Fig. 3h, is to run a cementing tool (not shown) and deploy a cement plug 41 at the lower end of the milled section Ά'.

Typically, the cement plug 41 might be 30m to 60m thick. If the cement plug 41 is sufficient for well abandonment then the method is complete. Alternatively, if the cement plug 41 is of insufficient length, then further cement plugs will be required. At the end of the method shown at Fig. 3h there will be a gap 'B' of 30m for example, between the lower end of the tubing 7a and the top of the cement plug 41.

Figure 4 shows the state of the well after the operations of figs 3a-h. The lower part of the well (zone 2) has been secured and a gap 'B' has been left between the lower end of the tubing 7a and the top of the cement plug 41. The next operation is to assess the quality of the cement over zone 1. Flowever due to the gap 'B' left below the lower end of the tubing 7a it is not necessary to repeat the milling operation of Fig. 3e. In order to expose the cement 3 of zone 1 for assessment of the cement quality, the steps shown in Figs 2a-d are carried out with the tubing 7 and control line 15 being cut at the upper end of zone 1. Upon completing the acid wash in Fig.2d, the lower part of the tubing 7b together with the attached control lines 15b are able to fall under gravity until they land on top of the cement plug 41.

Figure 5 shows the lower part of the tubing 7b and control lines 15b with the lower end 7a of tubing 7b located on the cement plug 41. There is now a gap of length 'B' between the upper end 7c of the lower part of the tubing 7b and the lower end 7d of the upper part of the tubing 7e. Note that the control lines 15 do not lie across the gap. This gap 'B 'has now exposed zone 1 for assessment of the quality of the cement 3. In a similar manner as previously described, a cement bond logging tool now assesses the cement quality and if poor, the well is suspended until a rig is available to pull the tubing 7e from the well. If the cement quality is good, then, again as previously described, a cementing tool is run to place a cement plug 42 in the lower part of gap 'B'. In the case where there are only two zones of interest, operations concerning the tubing 7b and 7e are complete and the final state of the well is shown in figure 6. The term "upper part" in this context means that this part is closer to the surface than the "lower part". In general, relative terms such as "upper" and "lower" are used to indicate directions and locations as the apply to the drawings.

If the cement quality at zone 1 is poor, an alternative to pulling the tubing 7e and control lines 15e from the well is to repeat the method as described in Figs. 2a-d at a shallower depth in the well and make a further cut in the tubing as shown in Figure 7a.

Figure 7a shows that when the further cut in the tubing 7 and control line 15 is made the cut section of tubing 7e and associated control line 15e drops down the well onto the previously cut tubing section 7b and exposes a new section of casing for evaluation of the cement bond. The tubing 7e and associated control line 15e with its lower end 7d is located on the upper end 7c of the lower part of the tubing 7b. There is now a gap of length 'C' between the tubing end 7f of the tubing 7e and the lower end 7g of the upper part of the tubing 7h. This gap 'C" has now exposed zone 3 for assessment of the quality of the cement 3.

As previously described, a cement bond logging tool now assesses the cement quality and if the cement quality is good, a cementing tool is run to place a cement plug 42 in the lower part of gap 'C' as shown in Figure 7b.

If the cement quality is poor at zone 3, the cut and drop operation is repeated by moving the cutting tool upward in the wellbore to depths closer to the surface and a further cuts in the tubing and control line are made until a zone with good quality cement is identified and a cement plug may be placed. By applying this cut and drop operation it is not required to provide costly surface equipment such as a drilling rig in order to pull the tubing and perform remedial operations. It will be appreciated that wells vary in complexity and there may be either more or less zones of interest than described above, however it will also be appreciated that the sequences of operation described heretofore can be applied as many times as are necessary and are not limited to two zones of interest.

Throughout the specification, unless the context demands otherwise, the terms 'comprise' or 'include', or variations such as 'comprises' or 'comprising', 'includes' or 'including' will be understood to imply the inclusion of a stated integer or group of integers, but not the exclusion of any other integer or group of integers. Furthermore, relative terms such as "upper", "lower" and the like are used herein to indicate directions and locations as they apply to the appended drawings and will not be construed as limiting the invention and features thereof to particular arrangements or orientations.

The foregoing description of the invention has been presented for the purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilise the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention as defined by the appended claims.