Apparatus and a method of removing a section of conduit from a wellbore through tubing

Abstract

A method of, and an apparatus for, removing a section (109VS) of conduit (109) from a wellbore (101) is described and includes:- i) running in a mechanical cutting tool assembly (150) into the wellbore (101) and actuating the mechanical cutting tool assembly (150) to create at least one substantially vertical cut (109VS) in the sidewall of at least a section (109VS) of the vertical length of the conduit (109); ii) running in a cutting and expansion assembly (250) into the wellbore (101) and actuating the cutting and expansion assembly (250) to firstly cut (#A) the conduit (109) at or close to one end of the substantially vertical cut in the sidewall and secondly (#B) at or close to the other end of substantially vertical cut (109VS) in the sidewall with substantially horizontal cuts (109VS) in order to create:- an upper section (109T), a lower section (109L) spaced apart from the upper section (109T); and a cut section (109VS) of the conduit (109) with the substantially vertical cuts (109VS) in the sidewall substantially contained therein; iii) expanding at least a portion of the length of the said cut section (109VS) such that at least the said portion of the length of the cut section (109VS) has a greater internal diameter than the outer diameter of at least one of the upper section (109T) and the lower section (109L); and iv) at least one of moving or permitting to move the cut section (109VS) within the wellbore in order to create a gap in the conduit (109) between the upper section (109T) and the lower section (109L).

Description

[0001]TITLE OF THE INVENTION “APPARATUS AND A METHOD OF REMOVING A SECTION OF CONDUIT FROM A WELLBORE THROUGH TUBING” TECHNICAL FIELD OF THE INVENTION The present invention relates to a through production tubing apparatus, where the apparatus is be run into the wellbore through tubing such as the production tubing and can be operated to remove a section of the tubing (such as to assist in abandoning the wellbore). The present invention also relates to a method of removing a section of conduit such as tubing and in particular such as production tubing (particularly but not exclusively to assist in abandoning a wellbore) through the conduit. BACKGROUND OF THE INVENTION When an oil and gas well reaches the end of its productive life, there are various requirements (particularly from a legislative point of view especially in relation to onshore / offshore / subsea hydrocarbon production wells) that must be met in order to abandon such a wellbore. One of those requirements is that the annulus barrier / cement barrier (which is located in the annular gap between the outside of the casing the inner surface of the wellbore (also known as the outer annulus)) must be verified to ensure that it is still intact to a sufficient extent in order to be able to act as a barrier (after the inner throughbore of the casing is plugged and thus after the wellbore is abandoned) to any hydrocarbons escaping the wellbore up through the outer annulus and thus past that annular barrier. In order to verify the said annulus barrier (which is typically formed of cement or other material pumped into the outer annulus during the installation phase (or pre- existing formation – a form of formation squeezing) of the casing which is likely to have been many years ago), conventional procedures require that the inner completion / production string must be removed in order to allow access to the inner surface of the casing, whereby that access to the inner surface of the casing is required so that a logging tool can be run into the well and can apply contact directly to the inner surface of the casing and in such a manner the logging tool can accurately determine whether the annular barrier located in the outer annulus on the outside of the casing provides a sufficiently good barrier to prevent hydrocarbons from escaping to surface via the wellbore up through the outer annulus and thereby bypassing the annular barrier. The skilled person will understand that hitherto it has not been possible to use a logging tool that doesn’t make contact directly with the inside surface of the casing because any fluids located between the logging tool and the inner surface of the casing are likely to provide inaccurate results and therefore, conventionally, an operator requires to cut the production tubing string at a location just below the required logging area and pull the upper section of cut production tubing string out of the wellbore in order to then be able to run the logging tool into the (much wider) throughbore of the casing within the wellbore, such that the production tubing string is no longer in the way of the logging tool. Indeed, Prior Art Figure 1 shows a conventional wellbore 1 that has come to the end of its productive life, where the wellbore 1 consists of a casing / liner string 3 which was installed in the bore hole that was drilled into the reservoir formation 5 and around which was installed (by pumping a suitable barrier material such as cement or the like from the surface) an annular barrier 7 typically in the form of cement 7 or the like. The conventional wellbore 1 typically also comprises a production tubing string 9 which, during the productive part of the life of the wellbore 1 would convey the produced hydrocarbon fluids such as oil and gas (as well as any produced water) from the reservoir formation 5, up through the throughbore of the production tubing string 9 to the surface of the wellbore 1 (and typically on to a production facility (not shown)) and, particularly for subsea wellbores 1, via for example a production riser (not shown) which extends from the sea bed surface 14 through the water column above). The production tubing string 9 is provided with a tubing retrievable subsurface safety valve (TRSSSV) 15 at its lower most end and which further comprises a production packer 16 on its outer surface which, in use, provides a seal which acts between the outer surface of the production tubing string 9 and the inner surface of the casing / liner string 3 and therefor acts to force all of the production fluids to enter the production tubing string 9 at a point below the TRSSSV 15 in order to provide the operator with control over the wellbore 1. The production tubing string 9 is also provided with a bottomhole gauge 17 which can provide data to the operator via a suitable conductor cable 19 which runs up to the subsea surface 14 of the wellbore 1. A pair of joints or collars 26 of the production tubing string 9 are also shown. In this example, the production tubing string 9 is connected to / hung off the wellhead 11 at its uppermost end by / via a tubing hanger 22; it will however be understood by those skilled in the art that the specific arrangement of the tubing hanger 22 and wellhead 11 can vary from well to well – for example, in some wells, the tubing hanger 22 lands off / is connected to the christmas tree (not shown) which is provided just above the wellhead 11. In order to allow the aforementioned logging tool to make contact with the inner surface of the casing / liner string 3, the conventional method employed in prior art plug and abandonment methods entails the following steps:- Prior Art – Stage 1 A wireline unit (not shown) is typically provided on a suitable vessel (not shown) at the surface of the body of water (not shown) generally located above the well head 11 of the conventional wellbore 1, and the wireline unit is used to run in and set a mechanical plug (not shown) toward the lower end of the production tubing string 9 in the tail pipe of the production packer 16 in order to seal the throughbore of the production packer 16 and therefore production tubing string 9 at that location. The wellhead 11 is provided at the mouth of the wellbore 1, and an outer conductor 18 extends downwardly from the wellhead 11 and is cemented in place by surface cement 21. Prior Art – Stage 2 The operator then typically runs in a tubing cutting tool (not shown) on wireline (not shown) using the wireline unit and actuates the cutting tool to sever the production tubing string 9 at a suitable location just above the production packer 16. Prior Art – Stage 3 A mechanical plug (not shown) is run in by the operator using the wireline unit through the (now severed) production tubing string 9 and is set approximately 200ft below the tubing hanger. The mechanical plug thus acts once set, as the second barrier required by safety legislation in order for the operator then to be able to remove the christmas tree (not shown) from the wellhead 11 at the subsea surface 14 of the wellbore 1. Prior Art – Stage 4 The operator then removes the wireline unit and instead skids a drilling rig or something with a similar capacity (not shown) over the well centre of the vessel and uses the drilling rig to remove the christmas tree and instead installs a BOP at the subsea surface 14 of the wellbore 1. Prior Art – Stage 5 The operator uses the drilling rig and in particular a workover unit provided on the drilling rig to attach to and remove to surface the entire upper section of the production tubing string 9 that was cut or severed in Prior Art – Stage 2 above. Prior Art – Stage 6 – Figure 2 – Pulling Tubing The operator can then run in a logging tool to the required logging area 25 of the wellbore 1 and, because the production tubing string 9 has been removed from the wellbore 1 at that location, the logging tool can make direct contact with the inner surface of the casing string 3 at the required logging area 25. Prior Art – Stage 7 If the logging tool confirms a sufficient / high quality annulus barrier in the form of the cement 7 at the required logging area 25, then the operator can move onto Prior Art – Stage 8. However, if the logging tool confirms that the annular barrier in the form of the cement 7 is not of a sufficiently good quality to continue to provide a barrier to any hydrocarbons leaking up the outer annulus between the reservoir formation 5 and the outer surface of the casing string 3, then one or more than one of the following conventional remediation techniques could be used:- i) formation testing; ii) a technique of slotting through the casing, jetting the annular barrier / cement 7 in order to wash out the below quality cement barrier and then pump in new cement at that location and such a conventional technique is disclosed in (currently unpublished) UK Patent Application No.2019133.4 filed on 4 December 2020 by HRG Well Solutions Limited and having the same inventor as this present patent application; iii) casing recovery; and / or iv) section milling. Prior Art – Stage 8 – Setting Casing Hole Cement Plug and Cut and Recover from Below Mud Line The operator can then set a casing hole abandonment plug by pumping in cement (or a similar material) into the throughbore of the casing string 3 from the surface through a suitable conduit such as drill pipe or coiled tubing and down into the wellbore 1 until it reaches the location of the required logging area 25 and the casing hole abandonment plug 27 forms a barrier at that location in order to reinstall the cap rock within the wellbore 1 in order to stop any unwanted hydrocarbons / produced water from flowing up the throughbore of the casing string 3 from the reservoir formation 5 below. Prior Art – Stage 9 - Figure 3 The operator can then cut the outer conductor 18 / wellhead 11 and inner casing string 23 at a location approximately 10ft below the mud line / subsea surface 14 and the upper part of the wellhead 11 / outer conductor 18 can be recovered by the operator to the surface vessel. The wellbore 1 is now in the configuration shown in Figure 3 where the casing hole abandonment plug 27 can also be seen in Figure 3. It will be appreciated by those skilled in the art that the conventional method of abandoning a well with an unverified annulus barrier is very costly in both expenditure and also in terms of the number of personnel that is required in order to remove the entire production tubing string 9 and typically an average of 32 personnel will be required to operate a conventional drilling unit (in addition to all the other personnel required to operate the drilling rig itself. It is therefore an object of the present invention in order to provide a lower cost (in both expenditure and personnel terms) apparatus and method for being able to abandon a wellbore through the production string and thereby not require such a drilling unit on a drilling rig nor the drilling rig itself to remove the production tubing string. Another prior art method of removing a section of conduit from a wellbore is disclosed in US Patent Number 11,885,190 to Aarbakke Innovation, A.S. et al (“US’190”), in which chemicals and / or explosives are used to cut through the production tubing in order to gain access to the and therefore that prior art system suffers from the disadvantage that significantly increased safety protocols and personnel are required when handling and / or transporting such chemicals and / or explosives which thereby significantly increases the time required and costs involved in deploying such a prior art system. In addition, said prior art system requires simultaneous cuts of the circumferential upper end and circumferential lower end of the production tubing to be performed along with a further simultaneous longitudinal cut of the production tubing section between said two circumferential upper end and circumferential lower end and therefore the simultaneous nature of all 3 cuts being performed at the same time significantly increases the complexity of the system required (see for example Figures 2 to 4 and Figures 8 to 10 of US’190 which shows said prior art tool as cutting all cuts at once) but also importantly means that if anything goes wrong with said cuts, the operator simply doesn't know which cutting step went wrong and hence the operator will not be able to validate if said three cuts have all been performed correctly. It is therefore a further object of the present invention to seek to reduce, mitigate or overcome said disadvantages and thereby provide a lower cost (in both expenditure and personnel terms) apparatus and method for being able to abandon a wellbore through the production string without requiring such chemicals and / or explosives to perform the cuts and also to provide the ability for the operator to validate each of the cutting steps when removing a section of the production tubing string. SUMMARY OF THE INVENTION According to a first aspect of the present invention there is provided a method of removing a section of conduit from a wellbore, the method comprising:- i) running in a mechanical cutting tool assembly into the wellbore and actuating the mechanical cutting tool assembly to create at least one substantially vertical cut in the sidewall of at least a section of the vertical length of the conduit; ii) running in a cutting and expansion assembly into the wellbore and actuating the cutting and expansion assembly to firstly cut the conduit at or close to one end of the substantially vertical cut in the sidewall and secondly at or close to the other end of substantially vertical cut in the sidewall with substantially horizontal cuts in order to create:- an upper section, a lower section spaced apart from the upper section; and a cut section of the conduit with the substantially vertical cuts in the sidewall substantially contained therein; iii) expanding at least a portion of the length of the said cut section such that at least the said portion of the length of the cut section has a greater internal diameter than the outer diameter of at least one of the upper section and the lower section; and iv) at least one of moving or permitting to move the cut section within the wellbore in order to create a gap in the conduit between the upper section and the lower section. Preferably, the method of the first aspect is conducted in the following order of steps:- a first part of step ii) is conducted whereby the cutting and expansion assembly is actuated to firstly cut the conduit at or close to one end (preferably an upper end) of the substantially vertical cut in the sidewall to create a substantially horizontal cut preferably at or towards the top of the cut section; step iii) is then conducted, and is more preferably then conducted once or after said first part of step ii) has been conducted and most preferably once said first part of step ii) has been conducted and concluded, to expand at least a portion of the length of the said cut section; and a second part of step ii) is then conducted, and is more preferably then conducted once or after said step iii) has been conducted and most preferably once said step iii) has been conducted and concluded, to expand at least a portion of the length of the said cut section whereby the cutting and expansion assembly is actuated to secondly cut the conduit, at or close to the other end of substantially vertical cut in the sidewall, with a substantially horizontal cut preferably at or towards the bottom of the cut section. Optionally, the method may further comprise the step of :- v) at least one of quantifying and / or qualifying a barrier in the wellbore. Optionally, the method may further comprise the step of :- vi) placing and / or installing a wellbore barrier in the wellbore. Step vi) may comprise pumping an abandonment plug which may be cement down through the throughbore of the upper section of the conduit and placing and / or installing the abandonment plug in the wellbore. Alternatively, step vi) may comprise running a sealing material such as a meltable material such as a meltable bismuth (Bi) based alloy and which may further comprise melting said alloy and which may further comprise allowing said alloy to cool to form a solid plug. According to the first aspect of the present invention there is also provided an apparatus for removing a section of conduit from a wellbore, the apparatus comprising:- i) a mechanical cutting tool assembly capable of being run into the wellbore, preferably as part of a first Bottom Hole Assembly (BHA) in a first trip into the wellbore, and further capable of being actuated to create at least one substantially vertical cut in the sidewall of at least a section of the vertical length of the conduit; ii) a cutting and expansion assembly capable of being run into the wellbore, preferably as part of a second Bottom Hole Assembly (BHA) in a second trip into the wellbore after said first trip into the wellbore has been conducted, and further capable of being actuated to firstly cut the conduit at or close to one end of the substantially vertical cut in the sidewall and secondly at or close to the other end of substantially vertical cut in the sidewall with substantially horizontal cuts in order to create:- an upper section, a lower section spaced apart from the upper section; and a cut section of the conduit with the substantially vertical cuts in the sidewall substantially contained therein; such that at least a portion of the length of the said cut section has a greater internal diameter than the outer diameter of at least one of the upper section and the lower section, and such that the cut section can be moved within the wellbore in order to create a gap in the conduit between the upper section and the lower section. Preferably, the conduit in the wellbore is one of a production tubing string or production liner (hereinafter referred to as production tubing string) in the wellbore. Preferably, the method is a method of plugging and abandoning a wellbore through the production tubing string. Preferably, the method comprises running in the mechanical cutting tool on an elongate member and more preferably the elongate member comprises one of wireline or slickline. In less preferred embodiments, the elongate member may be another elongate member such as a work string of at least one tubular such as coiled tubing or a plurality of drill pipe formed into a drill string. Preferably, step i) comprises running in a mechanical cutting tool assembly into the conduit of the wellbore and actuating the mechanical cutting tool assembly to typically move the mechanical blade vertically with respect to the static conduit in the wellbore, preferably in order to create at least one substantially vertical and more preferably, a continuous cut in the sidewall of at least a section of the vertical length of the conduit. Typically, the mechanical cutting tool assembly comprises a mechanical cutting implement which is preferably a blade and / or a mechanical blade and more preferably is a non-powered mechanical blade (and this has the advantage of not requiring downhole power and / or a downhole motor which would otherwise be required to power a rotating blade). Preferably, the mechanical cutting tool assembly comprises a slicing tool assembly which is actuable to slice through the conduit. Typically, the conduit is a production tubing string. Preferably, step ii) comprises running in a cutting and expansion assembly into the production tubing string of the wellbore and actuating the cutting and expansion assembly to firstly cut the production tubing string at or close to one end of the substantially vertical slice(s) in the sidewall and secondly at or close to the other end of substantially vertical slice(s) in the sidewall with substantially horizontal cuts. Preferably, step ii) comprises running in a cutting and expansion assembly into the production tubing string of the wellbore and actuating the cutting and expansion assembly to firstly cut the production tubing string at or close to one end of the substantially (and preferably continuous) vertical slice(s) in the sidewall and secondly at or close to the other end of substantially vertical slice(s) in the sidewall with substantially horizontal cuts. Preferably, step iii) of expanding at least a portion of the length of the said cut section such that at least the said portion of the length of the cut section has a greater internal diameter than the outer diameter of at least one of the upper section and the lower section results in the said at least a portion of the length of the said cut section (hereinafter also referred to as the expanded cut section) having a greater internal diameter then the outer diameter of the lower section of conduit such that there is a cross-sectional gap created therebetween. Preferably, step v) comprises at least one of quantifying and / or qualifying a barrier in the wellbore by deploying an apparatus to quantify and / or qualify the barrier. Preferably, step v) comprises at least one of quantifying and / or qualifying a barrier in the wellbore by deploying an apparatus to quantify and / or qualify the barrier on the outside of casing located in the wellbore. Preferably, step v) comprises at least one of quantifying and / or qualifying a barrier in the wellbore by deploying a logging apparatus to quantify and / or qualify the barrier on the outside of casing located in the wellbore. Preferably, step v) comprises at least one of quantifying and / or qualifying a barrier in the wellbore by deploying a logging apparatus through the conduit to quantify and / or qualify the barrier on the outside of casing located in the wellbore. Preferably, step v) comprises at least one of quantifying and / or qualifying a barrier in the wellbore by deploying a logging apparatus through the conduit and out to an inner surface of casing located in the wellbore to quantify and / or qualify the barrier on the outside of casing. Preferably, step v) comprises at least one of quantifying and / or qualifying a previously installed barrier in the wellbore by deploying a logging apparatus through the conduit and out to an inner surface of casing located in the wellbore to quantify and / or qualify the previously installed barrier on the outside of the casing. Preferably, step v) comprises at least one of quantifying and / or qualifying a previously installed barrier in the wellbore by deploying a logging apparatus through the conduit and out to an inner surface of casing located in the wellbore to log a required logging area of the wellbore to check the integrity of a previously installed annular barrier such as cement previously installed in the annulus between the outer surface of the casing and the inner bore of the wellbore. Preferably, step vi) comprises pumping an abandonment plug down through the throughbore of the upper section of the conduit and installing the abandonment plug in the region of the wellbore containing the barrier quantified and / or qualified in step vi). Typically, an additional step X) is conducted prior to step i) of the first aspect, where step X) comprises:- X) running in a casing collar locator (CCL) tool and a production tubing plug and obturating the throughbore of the production tubing string. Preferably, step i) of the first aspect is conducted prior to step ii) of the first aspect. Alternatively, step ii) of the first aspect is conducted prior to step i) of the first aspect. Embodiments of the present invention have the advantage that moving the tubing slicing tool axially within the conduit such as a production tubing string is capable of creating a vertical slice in the sidewall thereof of greater (and potentially much greater) length than the length of the slicer means itself. According to a second aspect of the present invention there is provided a method of creating vertical slices in the sidewall of a production tubing string, the method comprising the steps of:- a) sealing a lower section of the production tubing string with a sealing device; b) running in a tubing slicing tool comprising one or more slicing means into the throughbore of the production tubing string; c) actuating the slicing means to slice through the sidewall of the production tubing string; d) moving the tubing slicing tool axially within the production tubing string such that a vertical slice, of greater length than the length of the slicer means, is formed through the sidewall of the production tubing string; e) actuating the slicing means to stop slicing through the sidewall of the production tubing string; and f) pulling the tubing slicing tool out of the production tubing string and out of the wellbore. Optionally, the method of the second aspect can be conducted as part of the method of the first aspect of the present invention. Optionally, the method of the first aspect of the present invention comprises the method of the second aspect. Preferably, the term production tubing string used herein can also include a production liner in the wellbore. Preferably, the sealing device of the second aspect is run into a lower section of the production tubing string and is further preferably actuated to seal the throughbore of the lower section of the production tubing string at that location. Preferably, the tubing slicing tool of the second aspect forms part of the slicing tool assembly and / or the mechanical cutting tool assembly of the first aspect of the present invention. Typically, the tubing slicing tool comprises one or more anchors which may be actuated to set against and secure the anchor against the inner throughbore of the production tubing string. More preferably the tubing slicing tool comprises two vertically spaced apart anchors. More preferably, the distance between the vertically spaced apart anchors can be varied when at least one of the anchors is unset against the inner throughbore of the production tubing string. Typically, the slicing tool further comprises a telescopically arranged stroking tool which is preferably generally located in between the two anchors and which can be actuated to stroke outwards to increase the distance between the two anchors and can be stroked in to decrease the distance between the two anchors. Preferably, the tubing slicing tool comprising at least one and more preferably at least two slicing means which are preferably in the form of slicing blades which may be located proximate to one of the said anchors (and more preferably may be located proximate to the lower in use anchor). The said at least one and more preferably at least two slicing means are optionally located above the lower in use anchor but more preferably are located below the lower in use anchor. Preferably, the at least one slicing blade is a static blade (which typically does not comprise a rotating cutting element but rather comprises a static slicing blade edge) and which is arranged to clearly and / or cleanly slice through the sidewall of the conduit as the cutting blade edge is moved vertically along the length of the section of the conduit to be cut, such that the slicing action is wholly provided by the relative movement between the cutting blade edge of the slicing blade and the sidewall of the conduit which is preferably caused solely by the vertical movement of the slicing tool assembly (and thus the cutting blade edge of the slicing blade) with respect to the conduit sidewall. This provides embodiments of the present invention with the great advantage that rotating cutting blades are not required to be powered to cut through the conduit unlike prior art systems and that in turn provides the great advantage that downhole motors are not required to power such prior art rotating cutting blades. More preferably, the slicing blades are equi-spaced around the circumference of the slicing tool. Preferably, the slicing blades may be actuated between a closed configuration in which the slicing blades are spaced apart from the throughbore of the production tubing string and an open configuration in which the slicing blades make contact with and are capable of slicing, and are typically arranged to slice through, the sidewall of the production tubing string. Preferably, the slicing blades comprise a knife surface such as a knife surface having a slicing edge which slices solely by means of the operator moving the slicing tool relative to the conduit such that the slicing edge slices through the sidewall of the stationary conduit and more preferably the slicing blades are capable of being moved between the closed and open configurations by being rotated outwards such that a knife surface of the slicing blades is rotated outwards from the slicing tool into contact with the throughbore and more preferably into and through the sidewall of the production tubing string. Typically, the knife surface is arranged at an angle to the longitudinal axis of the production tubing string (where the longitudinal axis in a vertical wellbore is substantially vertical and is therefore substantially perpendicular to the horizontal plane) and preferably the angle is in the region of 45 degrees to the longitudinal axis of the production tubing string. Preferably, the slicing blades are arranged such that the greater the slicing force the slicing blades are applying to the sidewall of the production tubing string, the greater the force keeping the slicing blades in the open slicing configuration. Preferably, the slicing blade(s) is / are pivotally mounted to a frame member of the slicing tool by means of a respective pin member such that the respective blades can pivot about the pin member that affixes them to the frame member between:- i) a closed (stowed) configuration in which a slicing edge of the blade knife surface of the respective blade(s) is substantially or wholly contained entirely within the frame member such that the slicing edge of the blade knife surface is spaced apart from (and therefore does not make contact with) the inner throughbore of the conduit or production tubing string; and ii) an open (slicing) configuration in which each respective slicing blade can project through a respective blade aperture provided in the slicing tool, such that when the slicing blades are moved into the open configuration, the said slicing edge of the blade knife surface is rotated to project outwardly from the outer surface of the slicing tool and through the blade apertures such that the blade knife surface of each slicing blade is directed outwardly and upwardly (and is preferably at an angle of approximately 45 degrees or in an upper hook shape to the horizontal plane) and makes contact with and, initially passes / slices through the sidewall of the conduit when moving to the open configuration and subsequently slices through the sidewall of the conduit when the slicing tool is moved vertically within the wellbore and therefore moves relative to the conduit or production tubing string. Preferably, the method step d) further comprises the steps of:- i) actuating the stroker tool to stroke outwards to increase the distance between the pair of anchors such that there is an upper and a lower anchor; ii) optionally further comprises actuating the upper anchor to set; iii) optionally further comprises actuating the lower anchor to set; iv) optionally further comprises closing the stroker by a relatively short distance to actuate the slicer blades to move from the closed configuration to the open slicing configuration; v) optionally further comprises actuating the lower anchor to unset; vi) optionally further comprises closing the stroker by a relatively large distance to stroke the stroker tool closed to move the slicer blades upwards to form a vertical slice through the sidewall of the production tubing string; vii) optionally unsetting the upper anchor; and viii) optionally repeating steps i) to vii) as many times as required to provide the required length of vertical slice through the sidewall of the production tubing string. According to a third aspect of the present invention there is provided a method of removing a longitudinal section of production tubing from a production tubing string in a wellbore, the method comprising the steps of:- a) running a cutting and expansion assembly into the wellbore through the throughbore of the production tubing string into the region of production tubing to be removed; b) actuating the cutting and expansion assembly to form a horizontally arranged cut through, and around the circumference of, the sidewall of the production tubing at a first location at one end of the region of production tubing to be removed; c) actuating the cutting and expansion assembly to form a horizontally arranged cut through, and around the circumference of, the sidewall of the production tubing at a second location at the other end of the region of production tubing to be removed; d) wherein the combination of steps b) and c) results in the production tubing string being cut in two to provide an upper section and a lower section of production tubing with a gap therebetween. Optionally, the method of the third aspect can be conducted as part of the method of the first aspect of the present invention. Preferably the said one end of step b) of the third aspect of the present invention is at the lower end of the region of production tubing to be removed. Preferably the said one end of step c) of the third aspect of the present invention is at the upper end of the region of production tubing to be removed. Preferably the steps of the third aspect are conducted in sequential order a) to d). Alternatively, step c) of the third aspect is conducted prior to step b). Preferably the production tubing to be removed already has vertically extending slots or slices formed therein in accordance with the method of the second aspect of the present invention and that has the advantage that the tool which forms the vertically extending slots does not require to be run through production tubing which has had horizontally arranged cuts formed through its sidewall. Alternatively, the method of the second aspect is conducted prior to the forming of vertically extending slots formed through its sidewall. According to a fourth aspect of the present invention, there is provided a production tubing slicing tool comprising at least two slicing means equi-spaced around the circumference of the slicing tool; wherein the slicing blades are capable of being actuated between a closed configuration in which the slicing blades are spaced apart from the throughbore of the production tubing string and an open configuration in which the slicing blades make contact with and are capable of slicing through the sidewall of the production tubing string. Optionally, the apparatus for removing a section of conduit from a wellbore of the first aspect of the present invention comprises the production tubing slicing tool in accordance with the fourth aspect of the present invention. Optionally, the mechanical cutting tool assembly of the apparatus for removing a section of conduit from a wellbore in accordance with the first aspect of the present invention comprises the production tubing slicing tool in accordance with the fourth aspect of the present invention. Preferably, the slicing blades are moved between the closed and open configurations by being rotated outwards such that a knife surface of the slicing blades is rotated outwards from the slicing tool into contact with the throughbore and furthermore into and through the sidewall of the production tubing string. Typically, the knife surface is arranged at an angle to the horizontal axis of the production tubing string (the horizontal axis being perpendicular to the longitudinal axis of the production tubing string) and preferably the angle is in the region of 45 degrees to the horizontal axis of the production tubing string. Preferably, the slicing blades are arranged such that the greater the slicing force the slicing blades are applying to the sidewall of the production tubing string, the greater the force to keep the slicing blades in the open slicing configuration. According to a fifth aspect there is provided a provided a slicing tool assembly adapted to be run into a production tubing string and is capable of creating vertical slices in the sidewall of a section of the production tubing, the slicing tool assembly comprising:- an upper anchor; a lower anchor; a telescopic member located in between the upper and lower anchor; and a production tubing slicing tool according to the fourth aspect of the present invention; wherein the upper anchor and lower anchor are capable of being individually actuated to anchor against the inner throughbore of the production tubing string; and the telescopic member is capable of being actuated to stroke out to increase, and stroke in to decrease the distance between the upper anchor and the production tubing slicing tool, such that the telescopic member is capable of being actuated to move the production tubing slicing tool to slice through a vertical length of the sidewall of the production tubing string, where the said vertical length is a greater length than the length of the slicer means of the production tubing slicing tool. Optionally, the apparatus for removing a section of conduit from a wellbore of the first aspect of the present invention comprises the slicing tool assembly in accordance with the fifth aspect of the present invention. Optionally, the mechanical cutting tool assembly of the apparatus for removing a section of conduit from a wellbore in accordance with the first aspect of the present invention comprises the slicing tool assembly in accordance with the fifth aspect of the present invention. According to a sixth aspect of the present invention, there is provided a production tubing expansion tool for expanding a section of production tubing of a production tubing string, the expansion tool comprising:- a housing having an inner bore and an outer surface; and one or more expansion member(s) actuable between:- a run in hole configuration in which the one or more expansion member(s) is substantially relaxed such that the one or more expansion member(s) is spaced apart from the inner throughbore of the production tubing string; a compressed configuration in which the one or more expansion member(s) is compressed to store compression energy within the expansion tool; and an expanded configuration in which the one or more expansion member(s) is expanded by the compression energy such that it is capable of contacting the inner surface of the section of production tubing and is capable of increasing the inner diameter of the said section of production tubing. Optionally, the apparatus for removing a section of conduit from a wellbore of the first aspect of the present invention comprises the production tubing expansion tool in accordance with the sixth aspect of the present invention. Optionally, the mechanical cutting tool assembly of the apparatus for removing a section of conduit from a wellbore in accordance with the first aspect of the present invention comprises the slicing tool assembly in accordance with the sixth aspect of the present invention. Typically, the expansion tool further comprises at least one biasing means which is preferably one or both of a spring device and a piston and cylinder device, where the biasing device is capable:- of storing said compression energy in the compressed configuration; and of releasing said compression energy to expand the one or more expansion member(s) in the expanded configuration. Typically, the expansion tool further comprises a compression device which may be in the form of a compression rod and which is moveable with respect to the housing of the expansion tool in order to actuate the one or more expansion member(s) actuable from the run in hole configuration to the compressed configuration. Preferably, the one or more expansion member(s) are elongate members having one end secured to the compression device and another end to the housing of the expansion tool. Preferably, the compression device is capable of moving the end of the one or more expansion member(s) secured to the compression device with respect to the other end, thereby causing compression of the one or more expansion member(s) and thereby causing compression of the at least one biasing means. Preferably, the other end of the one or more expansion member(s) is secured to an outer surface of the housing such that an inner portion of the one or more expansion member(s) is located within the inner bore of the housing and an outer portion of the one or more expansion member(s) is located outside of the housing. Preferably, compression of the one or more expansion member(s) results in the outer portion of the one or more expansion member(s) being biased outwardly. Preferably, the one or more elongate expansion member(s) are formed from a spring material and which are capable of elastic deformation. More preferably, the one or more elongate expansion member(s) comprise a length greater than their width and which transition from the inner bore of the housing to the outer surface of the housing by passing through a respective aperture formed in the housing. Typically, the one or more expansion member(s) are actuable between the compressed and expanded configurations when the expansion tool exits a lower section of integral or unimpaired (unsliced) production tubing into said section of production tubing. Typically, said section of production tubing has been formed with vertical slices by the production tubing slicing tool in accordance with the fourth aspect of the present invention and by the method in accordance with the fourth aspect of the present invention. Preferably, the one or more expansion member(s) are capable of expanding the said portion of the when in the expanded configuration such that the said portion has a greater internal diameter than the outer diameter of at least one part of the remaining production tubing. Preferably, there are a plurality of expansion members, preferably arranged with their respective said one ends substantially equi-spaced around the circumference of the compression device. Typically, the plurality of expansion members are provided with a frangible connection at their other end to the outer housing such that the frangible connection is breakable if the expansion tool is force into an upper section of production tubing string when it is being pulled out of the wellbore through the upper section of the production tubing. According to a seventh aspect there is provided a provided a cutting and expansion tool assembly adapted to be run into a production tubing string and which is capable of cutting and expanding a section of the production tubing, the cutting and expansion tool assembly comprising:- an upper anchor; a production tubing cutting tool capable of forming a horizontally arranged cut through, and around the circumference of, the sidewall of the production tubing at a first location at one end of the region of production tubing to be removed; a telescopic member located in between the upper anchor and the production tubing cutting tool; and an expansion tool according to the sixth aspect of the present invention. wherein the upper anchor is capable of being actuated to anchor against the inner throughbore of the production tubing string; and the telescopic member is capable of being actuated to stroke out to increase, and stroke in to decrease the distance between the upper anchor and the production tubing cutting tool such that the telescopic member is capable of being actuated to move the production tubing cutting tool. Optionally, the apparatus for removing a section of conduit from a wellbore of the first aspect of the present invention comprises the cutting and expansion tool assembly in accordance with the seventh aspect of the present invention. Optionally, the mechanical cutting tool assembly of the apparatus for removing a section of conduit from a wellbore in accordance with the first aspect of the present invention comprises the cutting and expansion tool assembly in accordance with the seventh aspect of the present invention. Preferably the cutting and expansion tool assembly further comprises a spacer member having a predetermined length and which is typically located in between the production tubing cutting tool and the expansion tool and which serves to separate those two tools by the length of the spacer tool. The preferred method of conveying the respective tools and / or assemblies of the first through to the seventh aspects of the present invention is wireline. The accompanying drawings illustrate presently exemplary embodiments of the disclosure, and together with the general description given above and the detailed description of the embodiments given below, serve to explain, by way of example, the principles of the disclosure. In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. 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. The present invention is susceptible to embodiments of different forms. Specific embodiments of the present invention are shown in the drawings and herein will be described in detail, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognised that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results. The following definitions will be followed in the specification. As used herein, the term "wellbore" refers to a wellbore or borehole being provided or drilled in a manner known to those skilled in the art. The wellbore may be ‘open hole’ but is more usually typically ‘cased’, being lined with a tubular string such as a liner and / or casing string. Reference to up or down will be made for purposes of description with the terms "above", "up", "upward", "upper" or "upstream" meaning away from the bottom of the wellbore along the longitudinal axis of a work string toward the surface and "below", "down", "downward", "lower" or "downstream" meaning toward the bottom of the wellbore along the longitudinal axis of the work string and away from the surface and deeper into the well, whether the well being referred to is a conventional vertical well or a deviated well and therefore includes the typical situation where a rig is above a wellhead, and the well extends down from the wellhead into the formation, but also horizontal wells where the formation may not necessarily be below the wellhead. Similarly, ‘work string’ refers to any tubular arrangement for conveying fluids and / or tools from a surface into a wellbore. In the present invention, production tubing string is the preferred string for conveying fluids and wireline is the preferred work string for conveying tools into / out of the wellbore (although other suitable conveyance means could be used such as slickline). Also, the slicing tool disclosed herein is described as being used to slice through a production tubing string, but it could also be used to slice through a production liner (and therefore references to the slicing tool slicing through a production tubing string should be read with that possibility in mind). The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one embodiment can typically be combined alone or together with other features in different embodiments of the invention. Additionally, any feature disclosed in the specification can be combined alone or collectively with other features in the specification to form an invention. Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary embodiments and aspects and implementations. The invention is also capable of other and different embodiments and aspects, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention. Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention. 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. 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. In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase "comprising", it is understood that we also contemplate the same composition, element or group of elements with transitional phrases "consisting essentially of”, "consisting", "selected from the group of consisting of”, “including” or "is" preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words “typically” or “optionally” are to be understood as being intended to indicate optional or non-essential features of the invention which are present in certain examples but which can be omitted in others without departing from the scope of the invention. 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 and method described herein are understood to include plural forms thereof and vice versa. BRIEF DESCRIPTION OF AND INTRODUCTION TO THE DRAWINGS Embodiments of one or more apparatus and method(s) in accordance with the present invention will now be described, by way of example only, and with reference to the accompanying drawings, in which:- Figure 4(a) is a schematic side view of a wellbore which has typically come to the end of its productive life and which is to be plugged and abandoned by using the embodiments of apparatus and method in accordance with the present invention, where the wellbore shown in figure 4(a) is shown in the state prior to conducting any operations in accordance with the present invention; Figure 4(b) is a more detailed view of the wellbore of figure 4(a), in particular showing the lower section thereof in more detail; Figure 5 shows a schematic side view of the wellbore of figure 4(b) after a first stage of operation using the method and apparatus according to the present invention has been conducted and more particularly shows the wellbore as having had a bridge plug set and actuated within the production tubing string at a location below the bottomhole gauge and therefore below the section of the wellbore that requires to be blocked or plugged and therefore below the section of the production tubing string which will be cut according to subsequent stages of the embodiments of method and apparatus of the present invention as will be subsequently described; Figure 6(a) a schematic side view of the wellbore at a next stage of operation on from that of Figure 5 using the embodiments of the method and apparatus according to the present invention and shows the production tubing string as having had a vertical slicing tool bottomhole assembly (BHA) apparatus in accordance with the present invention as having been run into the inner throughbore of the production tubing string and into the vicinity of the required logging area; Figure 6(b) shows a part cross sectional side view of the vertical slicing tool BHA 150 that is run into the inner throughbore of the production tubing string of figure 6(a) by the operator, where the vertical slicing tool BHA is shown in figure 6(b) as being in the run in hole (RIH) configuration / position, and where the vertical slicing tool BHA comprises from top to bottom (although it should be clearly noted that the BHA that could be run could well be a different configuration to that described herein and that the below described BHA is just an example of one type of BHA that could be run):- i) an upper anchor 152; ii) a stroker tool 160; iii) a lower anchor 170; and iv) a blade tool 180; Figure 6(c) is a part cross sectional side view of the vertical slicing tool BHA of figure 6(b), but in figure 6(c) the vertical slicing tool BHA is shown as having being actuated by the operator to the next stage of operation of the apparatus and method in accordance with the present invention, whereby the vertical slicing tool BHA has been run to depth and has been operated to stroke open, but with both its upper and lower anchors not having been set yet; Figure 6(d) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(c), where the vertical slicing tool BHA has been actuated by the operator to actuate its lower anchor to set the lower anchor in place against the inner throughbore of the production tubing string; Figure 6(e) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(d), where the vertical slicing tool BHA has been actuated by the operator to set its upper anchor (in addition to its lower anchor) in place against the inner throughbore of the production tubing string, such that both upper and lower anchors are now set, and the stroker tool of the vertical slicing tool BHA has been closed by a relatively short distance such as one quarter inch or thereabouts in order to open a slicing blade of the blade tool which will cut through and therefore puncture the sidewall of the production tubing string at that location; Figure 6(f) shows a cross sectional side view of the lower end of the vertical slicing tool BHA in the RIH configuration / position of figure 6(b), and more particularly showing the interior cross section of the blade tool which in turn includes a blade housing and blades, where the blades are shown in the closed position; Figure 6(g) is a cross sectional side view of the blade tool of figure 6(f), but in figure 6(g) the blades have been moved radially outwardly into the open (slicing) configuration; Figure 6(h) is an outer side view of the blade tool of figure 6(f) and thus shows the blades in the closed (stowed) position; Figure 6(i) is an outer side view of the blade tool of figure 6(g) and therefore shows the blades in the open (slicing) configuration; Figure 6(j) – upper half thereof - is a cross sectional side view of the blade tool of figure 6 (f) shows the blades as having being returned from the open configuration of Figure 6(i) to the closed configuration of figure 6 (f) and also shows the itemised parts thereof; Figure 6(j) – lower half thereof - is an outer side view of the blade tool of figure 6 (f) and therefore shows the outer side view of the blade tool with the blades as having being returned from the open configuration of Figure 6(i) to the closed configuration of figure 6 (f); Figure 6(k) is a side exploded view showing the itemised parts of the main inner parts of the blade tool of figure 6 (g) including the blades, blade hinge plate, actuating arm and actuating arm stop; Figure 6(L) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(e), where figure 6(L) shows that the lower anchor has been unset by the operator (with the upper anchor still in the set configuration) and the stroker tool remains substantially stroked out and the blade tool remains in the open (slicing) configuration in preparation for the next stage shown in figure 6(m); Figure 6(m) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(L), where the lower anchor remains unset, the blades remain in the open (slicing) configuration and the stroker tool has been actuated by the operator to fully stroke closed such that it is at its shortest or minimum possible axial length and thus the blades will have moved upwards in the open (slicing) position, cutting or slicing through the sidewall of the production tubing string in order to create a vertical aperture or slice through the sidewall of the production tubing string; Figure 6(n) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(m), where the bottom anchor of the vertical slicing tool BHA has been actuated by the operator to set and thus anchor against the inner surface of the production tubing string throughbore and the stroker remains closed (i.e. fully stroked in) and the upper anchor has been unset by the operator and the blades remain in the open (slicing) configuration and thus continue to project through the sidewall of the production tubing string; Figure 6(o) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(n), where the vertical slicing tool BHA is shown in figure 6(o) as having had the stroker tool fully stroked out by actuation of the operator and therefore the stroker tool is shown in the open configuration such that it is at its longest or maximum possible axial length and the upper anchor remains unset (and therefore allows the stroker tool to fully stroke upwards and outwards) and the blades remain open and therefore continue to project through the sidewall of the production tubing string, with any slack on the conveyance method such as the wireline having been taken up by the conveyance unit, such as a wireline unit, at the surface of the wellbore; Figure 6(p) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(o), where the top anchor of the vertical slicing tool BHA has been actuated by the operator at the surface of the wellbore to set and thus anchor itself and thus the vertical slicing tool BHA against the inner surface of the production tubing string throughbore and furthermore shows the lower anchor has having been actuated by the operator to unset (and therefore remove any anchoring against the inner surface of the production tubing string throughbore) and the blades continue to project through the sidewall of the production tubing string; Figure 6(q) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(p), and where the vertical slicing tool BHA of figure 6(q) is shown with the top anchor remaining set, the stroker tool as having been actuated by the operator to stroke upwards and inwards and therefore the stroker tool is shown in the closed position again, and the lower anchor is then actuated by the operator to set and thus anchor itself and thus the vertical slicing tool BHA against the inner surface of the production tubing string throughbore, and furthermore shows the stroker tool just immediately prior to having then been actuated by the operator to stroke open by a relatively small distance such as a quarter inch or more in order to move the blades from the open (slicing) configuration to the closed (stowed) configuration (which is shown in figure 6(r)) so that the blades no longer continue to project through the sidewall of the production tubing string and that next step occurs when no further slicing or cutting of the production tubing string is required because a sufficiently long cut or slice has already been formed through the sidewall of the production tubing string; Figure 6(r) is a cross sectional side view of the vertical slicing tool BHA and which shows the next stage of operation of the vertical slicing tool BHA on from that of figure 6(q), whereby the stoker tool has been actuated by the operator to stroke open by a relatively small distance such as a quarter inch or more in order to move the blades from the open (slicing) configuration to the closed (stowed) configuration so that the blades no longer continue to project through the sidewall of the production tubing string and this step occurs when no further slicing or cutting of the production tubing string is required because a sufficiently continuous long cut or slice has already been formed through the sidewall of the production tubing string, and in addition figure 6(r) shows that the operator has actuated both the upper and lower anchors to unset and thus the weight of the vertical slicing tool BHA is therefore once again taken up by the wireline unit at the surface and the vertical slicing tool BHA can be pulled out of hole / wellbore (POOH); Figure 7(a) shows a schematic side view of the wellbore at the next stage of operation on from that of Figure 6(a) using the embodiments of the vertical slicing tool BHA apparatus and method according to the present invention to form vertical slices through the sidewall of the production tubing string as shown in Figures 6(b) to 6(r), where the vertical slices through the sidewall of the production tubing string are shown as 109VS and the vertical slicing tool BHA has been POOH, and furthermore shows that an embodiment of a cutting tool bottomhole assembly (BHA) in accordance with a further aspect of the apparatus and method of the present invention can be run into the wellbore and in particular into the throughbore of the production tubing string shown in figure 7(a), where the cutting tool BHA is shown in figure 7(b) in the running in hole (RIH) configuration / position; Figure 7(b) is a part cross sectional side view of the cutting tool BHA in the RIH configuration / position as mentioned in figure 7(a), where the cutting tool BHA is shown as mainly comprising, from top to bottom (although it should be clearly noted that the BHA that could be run could well be a different configuration to that described herein and that the below described BHA is just an example of one type of BHA that could be run):- i) an upper anchor 252; ii) a stroker tool 260; iii) a tubing cutter tool 273; iv) a spacer (which could be a pipe / bar / rod) 279; and v) an expansion tool 280; Figure 7(c) is a part cross sectional side view of the cutting tool BHA and which shows the next stage of operation of the cutting tool BHA on from that of figure 7(b) and which shows the cutting tool BHA as having been lowered down through the throughbore of the production tubing string until the very lower end of the cutting tool BHA (and more particularly the lower end of the expansion tool) makes contact with and tags the upper surface of the previously installed bridge plug in order to actuate expansion of the expansion tool provided in the cutting tool BHA, such that the outer surface of the expansion tool is outwardly radially expanded into contact with the inner surface of the lower end of the sliced section of the production tubing string throughbore at a location (which may be a predetermined location) or distance some way below the lower end of the sliced portion 109vs of the production tubing string; Figure 7(d) is a part cross sectional side view of the cutting tool BHA and which shows the next stage of operation of the cutting tool BHA on from that of figure 7(c) and which shows the cutting tool BHA as having been actuated by the operator at the surface of the wellbore in order to actuate the one or more cutting arms 274 of the tubing cutter tool 273 to move radially outwardly to perform a substantially horizontally arranged cut through the sidewall of the production string tubing at the bottom of the vertically slices 109VS at a location shown in figure 7(e) as #A; Figure 7(e) shows a schematic side view of the wellbore at the next stage of operation on from that of Figure 7(a) after using the embodiment of the cutting tool BHA of figure 7(d), such that the horizontal cut through the sidewall and furthermore around the circumference of the production tubing string as has having been conducted at location #A, and thus the production tubing string has now been cut in two into an upper section 109U and a lower section 109L at location #A; Figure 8(a) shows a schematic side view of the wellbore at the next stage of operation on from that of Figure 7(e) and in particular shows the next stage of operation of the cutting tool BHA in accordance with the present invention on from that of Figure 7(d), where the one or more cutting arms 274 of the tubing cutter tool 273 have either been actuated by the operator to move radially inwardly to retract into the cutter tool body 275 or if the cutter arms 274 have been trapped between the upper 109U and lower 109L sections of the production tubing string, the cutting arms have been sheared off and the cutting tool BHA has been POOH and a new cutting tool BHA has been RIH, and moreover the cutting tool BHA has been pulled and thus moved upwards by the operator lifting the wireline such that the expansion tool is in line with / adjacent to the inner surface of the production tubing string just above location #A, such that the expansion tool can now expand outwards and therefore will expand the now free end of the upper section 109U of the cut production tubing string (and more particularly the lower free ends of the vertical slices 109VS) outwards such that it / they splay outwards; Figure 8(b) is a part cross sectional side view of the cutting tool BHA and which shows the next stage of operation of the cutting tool BHA on from that of figure 7(d) and as described above for Figure 8(a), where Figure 8(b) shows the cutting tool BHA as having been picked up after completing the cut at location #A (as described in relation to previous stage figure 7(e) and where the expansion tool expands the lower end of the upper section 109U of the production tubing string at the bottom of the vertical tubing slices 109VS as discussed above in relation to the previous stage figure 8(a); Figure 8(c) shows, from left to right:- i) an outer side view (at the upper left hand corner of figure 8(c)) and a cross sectional view (at the lower left hand corner of Figure 8(c)) of the expansion tool 280 in the run in hole (RIH) configuration 280RIH; ii) an outer side view (at the upper middle of figure 8(c)) and a cross sectional view (at the lower middle of figure 8(c))) of the expansion tool 280 in which the compression rod upwards has been forced upwards relative to the rest of the expansion tool 280 in order to place the expansion tool 280 in a compressed configuration 280C, and iii) an outer side view (at the upper right hand corner of figure 8(c)) and a cross sectional view (at the lower right hand corner figure 8(c)) of the expansion tool 280 in the expanded configuration 280E that the expansion tool 280 takes up when it is able to push the vertical tubing slices 109VS outwards; Figure 8(d) shows an outer view of an expansion tool body of the expansion tool of figure 8(c); Figure 8(e) shows a cross sectional view of the expansion tool body of figure 8(d); Figure 8(f) shows an exploded side view of the reactive piston, retainer and spring of the expansion tool of figure 8(c); Figure 8(g) shows a side view of the compression rod and two of the leafs of the expansion tool of figure 8(c) when the expansion tool 280 is in the compressed configuration 280C; Figure 8(h) shows a side view of the compression rod and two of the leafs of the expansion tool of figure 8(c) when the expansion tool 280 is in the RIH configuration 280RIH; Figure 8(i) shows a side view of the outer body 282, the compression rod and two of the leafs of the expansion tool of figure 8(c) when the expansion tool 280 is in the expanded configuration 280E; Figure 9(a) is a part cross sectional side view of the cutting tool BHA and which shows the next stage of operation of the cutting tool BHA on from that of figure 8(b), where after the operator has received confirmation that the vertical tubing slices 109VS of the production tubing string have been expanded, the anchor provided at the upper end of the cutting tool BHA is actuated by the operator to set against the inner throughbore surface of the production tubing string at a suitable location such that the tubing cutter tool 273 is able to be actuated by the operator to radially extend the cutting arms thereof outwards to cut through the sidewall of the production tubing string at location #B, which is typically approximately one foot above the top end of the vertical tubing slices 109VS that were formed through the production tubing string, such that the tubing cutter tool 273 cuts all the way round (360 degrees) through the circumference of the sidewall of the production tubing string at location #B as shown in figure 9(b) and figure 9(c); Figure 9(b) is a schematic side view of the wellbore on the next stage of operation on from that shown in figure 9(b), where the tubing cutter tool 273 of figure 9(a) has cut through the production tubing string of figure 9(b) at location #B; Figure 9(c) is a more detailed view of the wellbore of figure 9(b), particularly in the region of the location #B of the horizontal cut which has been made through the sidewall of the production tubing string by the tubing cutter tool 273 of figure 9(a); Figure 10(a) is a schematic side view of the wellbore on the next stage of operation on from that shown in figure 9(b) and shows the vertically sliced tubing 109VS having been moved downwards by the operator actuating the stroker tool 260 to lower the tubing cutter tool (in the configuration as shown in figure 10(b)) with respect to the upper anchor tool 252 to cause the cutting arms 274 of tubing cutter tool 273 to move the upper end of the vertically sliced tubing 109VS downwards and, because it is splayed at its lower end, the lower end thereof 109VS is moved into the annulus between the outer surface of the lower section of the production tubing string and the inner surface of the casing at that location; Figure 10(b) is a part cross sectional side view of the cutting tool BHA and which shows the next stage of operation of the cutting tool BHA on from that of figure 9(a), where the cutting arms 274 of the tubing cutter tool 273 are radially extended outwards and are in the configuration used to push the vertically sliced tubing 109VS downwards and outwards into the annulus between the outer surface of the production tubing string and the inner surface of the casing as shown in figure 10(a); Figure 10(c) shows a more detailed close up view of the section 109VS of the production tubing string that was sliced and cut out of the rest of the production tubing and which has been moved downwards and is being pushed outwards into the annulus as shown in figure 10(a); Figure 10(d) is a schematic side view of the wellbore on the next stage of operation on from that shown in figure 10(c) where the sliced production tubing string has been fully pushed downwards and outwards into the annulus by the operator actuating the stroker tool 260 to lower the tubing cutter tool (in the configuration as shown in figure 10(b)) with respect to the upper anchor tool 252; Figure 11 is a part cross sectional side view of the cutting tool BHA and which shows the next stage of operation of the cutting tool BHA on from that of figure 10(b) and the next stage of operation in the wellbore as shown in figure 10(d), where the cutting arms are closed by the operator actuating the tubing cutter tool, and the operator further actuates the upper anchor of the cutting tool BHA to unset / close and the cutting tool BHA is able to now be pulled out of hole (POOH) by the operator; Figure 12 is a schematic side view of the wellbore on the next stage of operation on from that shown in figure 11 and therefore shows the next stage of operation of an embodiment in accordance with the method of the present invention, where a logging tool (not shown) can be run into the wellbore through the throughbore of the upper section of the production tubing string and can now log the required logging area as shown in figure 12 (because the section of production tubing string that would have been in the way has now been removed by firstly slicing it, secondly cutting it and thirdly moving it downwards in the annulus) and thus the logging tool can directly access the sidewall of the casing in order to provide a high quality log of the annular barrier (such as cement) that was originally installed in the outer annulus (in between the outer surface of the casing and the inner surface of the drilled borehole); and Figure 13 shows the next and final stage of operation of an embodiment in accordance with the method of the present invention, where an abandonment plug, such as a section of barrier material (such as cement or other suitable material) can be pumped down through the remaining upper section of the production tubing string and out the lower end thereof into the area of the wellbore to be plugged, such as that area between:- i) the vicinity of (and which could include a distance above) the lower end of the upper section of production tubing string that remains in the well; and ii) the vicinity of (and which could include a distance below) the upper end of the lower section of production tubing string that remains in the well. DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS OF PRESENT INVENTION Figure 4(a) shows a schematic view of a wellbore that is to be plugged and abandoned by an operator (typically due to the wellbore 101 having come to the end of its productive life) using embodiments of a method and apparatus in accordance with the present invention that will now be described. The skilled reader will note that the same reference numerals but with the addition of 100 have been used for the various components of the wellbore 101 shown in Figure 4(a) as compared with the various same components as shown in the wellbore 1 shown in the prior art Figure 1 for ease of reference of the skilled reader. Accordingly, those same components will not now be described again. For example, the wellhead 111, subsea surface 114, surface cement 121 and outer conductor 118 are all shown in Figures 4(a) onwards. Figure 4(b) shows a more detailed close up view of the required logging area 125 of the wellbore 101. The various stages of the apparatus and method for plugging and abandoning the wellbore 101 in accordance with the present invention will now be described. Typically, the various steps or stages are conducted in turn in the order as described below but the skilled person will understand that certain stages could be performed earlier or later than described below without departing from the scope of the invention. There are five overall main parts of the method of through production tubing string 109 plug and abandonment that will be described, which could all be operated by the one service company or some of which could be operated by different service companies within the oil & gas industry, and some of which are optional, namely i) Stages 1(a) and (b) below - the running in of a casing collar locator (CCL) tool and a bridge plug 130 or other suitable means of obturating the throughbore 109T of the production tubing string 109, where the CCL tool and bridge plug 130 or the like can be run into the wellbore 101 in a single trip or in separate trips; ii) Stages 2 to 11 below - the running in and operation of a slicing tool BHA 150 to create substantially vertical slices 109VS in the production tubing string 109; iii) Stages 12 to 18 below - the running in of a cutting and expansion BHA 250 to firstly cut the production tubing string 109 with substantially horizontal cuts #A; #B in order to create a cut section 109VS of the production tubing string 109, and then to expand the cut section 109VS and then to drop the cut section 109VS within the wellbore 101 in order to create a gap in the production tubing string 109; iv) Stage 19 below - the running in of a logging tool to check the integrity of the previously installed annular barrier (i.e. the cement barrier in between the outer surface of the casing 103 and the inner surface of the borehole of the reservoir formation 105); and v) Stage 20 below - pumping of an abandonment plug 125 down through the throughbore 109T of the production tubing string 109 and installing the abandonment plug 125 in the desired location in the region of the wellbore 101 that was logged in part iv) above. Each stage will now be described in more detail. Stage 1(a) – Locating production tubing string collars – Figure 4(a) and (b) A casing collar locator (CCL) tool (not shown) (or other suitable tool for locating collars in a production tubing string) is run by the operator from the surface of the wellbore 101 down through the production tubing string 109 to a general location at which the operator would like to plug the wellbore such as such as the location shown in Figure 4(a) and (b) that is located just above the bottomhole gauge 117. The CCL tool is run into the throughbore 109T of the production tubing string 109 by any suitable conveyance means such as wireline (not shown) or the like. Wireline is the preferred conveyance means rather than, for example, drill pipe in order to keep overall costs as low as possible because wireline units can typically be deployed on much more cost-effective sea going vessels than drill strings which would typically require a drilling rig. The CCL tool is run into the wellbore 101 by the operator and is operated to confirm the depth of a pair of couplings 126 of the production tubing string 109 and therefore, in doing so, locate a suitable section 109VS of the production tubing string 109 for slotting (as will be described subsequently) and importantly that section 109VS of production tubing string 109 for slotting should be located in between the pair of collars 126 of the production tubing string 109, otherwise the slotting / cutting tools to be described subsequently will have difficulty and / or will not be able to slot / cut through the much thicker sidewall of the collars 126. Any suitable conventional CCL tool can be used for this stage such as:- i) CCL Tool offered by Hunting International of Portlethen, Scotland - for example Hunting’s Titan Instruments CCL Logging tool:- http: / / www.hunting- CCL- TechDataSheet-V1.pdf or ii) CCL Tool offered by Read Cased Hole of Aberdeen, Scotland - for example Hunting’s Titan Instruments CCL Logging tool:- https: / / www.readcasedhole.com / wp-content / uploads / 2019 / 04 / READ-CCL- TechDataSheet-V1.pdf Other suitable conventional CCL Tools could also be used. The CCL tool is then pulled out of the wellbore 101 (POOH). The skilled person will however note and understand that it is however possible for stage 1(a) and stage 1b) to be run into the wellbore 101 (RIH) and therefore POOH in a single (combined) trip (i.e. both are RIH and POOH on the one wireline trip). Stage 1(b) – Setting of bridge plug – Figure 5 A bridge plug 130 (or other suitable production tubing string throughbore 109T sealing device) is RIH by the operator from the surface of the wellbore 101 down through the production tubing string 109 to a suitable location within the inner throughbore 109T of the production tubing 109 such as the location shown in Figure 5 that is located just below the bottomhole gauge 117 and in particular down to and more preferably to just below the required logging area 125 (typically to around 50ft or so below the required logging area 125). The bridge plug 130 is run into the throughbore of the production tubing string 109 by any suitable conveyance means such as wireline (not shown) or the like. Wireline is again the preferred conveyance means rather than, for example, drill pipe (not shown) or coiled tubing (not shown) in order to keep overall costs as low as possible because wireline units can typically be deployed on much more cost-effective sea going vessels than drill strings which would typically require a drilling rig. The bridge plug 130 is then set by the operator at its in use location (as shown in Figure 5) in order to block or otherwise obturate the throughbore 109T of the production tubing string 109 at that location so as to seal the throughbore 109T at that location and therefore prevent any remaining production fluids located in the reservoir formation from progressing any further up the throughbore 109T than the location of the bridge plug 130. Any suitable bridge plug 130 can be used for this stage such as:- i) A bridge Plug offered by Core Laboratories of Aberdeen, Scotland - for example https: / / www.corelab.com / owen / bridgeplugs-landing or ii) A bridge plug offered by Baker Hughes of Aberdeen, Scotland - for example BH’s N-1 Wireline set bridge plug:- https: / / global.shopbakerhughes.com / bridge-plug-n-1-wireline-set.html Other suitable conventional bridge plugs 130 could also be used. After the operator has confirmation that the bridge plug 130 is set, the operator will pick the wireline up by a suitable height such as 5ft or so, and will then RIH the wireline and tag the upper surface of the bridge plug 130 (i.e. will set down weight on the upper surface of the bridge plug 130) to ensure that the bridge plug 130 is set correctly; the operator can observe the reduction in weight at the surface of the wellbore 101 and thereby know that the bridge plug 130 has been set correctly. The wireline is then pulled out of the wellbore 101 (POOH), leaving the bridge plug 130 set in the location within the throughbore 109T of the production tubing string 109 as shown in Figure 5, thereby sealing / obturating the throughbore 109T at that location such that no fluids can flow past the bridge plug 130 and therefore no fluids can flow through the throughbore 109T at that location. Other suitable means of sealing the throughbore 109T could also be used instead of the bridge plug 130. Stage 2 – Providing vertical slices / cuts 109VS through the sidewall of the production tubing string 109 – Figure 6(a) and 6(b) Once the operator has pulled the conveyance method, such as the wireline (not shown) out of the wellbore 101 (by operating a wireline unit (not shown) at the surface to reel in the wireline) having set the bridge plug 130 (i.e. Stage 1(b) above), the operator then attaches a slicing tool BHA 150 (see Figure 6(b) in its running in hole (RIH) position / configuration such as that shown in Figure 6(b) to the lower end of the wireline (not shown) and the operator then runs the slicing tool BHA 150 into the wellbore 101 through the throughbore 109T of the production tubing string 109 (by operating the wireline unit at the surface to pay out or reel out the wireline) until the slicing tool BHA 150 is located within the required logging area 125 of the throughbore 109T the wellbore 101 (i.e. around 50 feet above the set bridge plug 130). It should however be known that the slicing tool BHA 150 can be run in on any suitable conveyance means but is preferably run in on wireline (not shown) using a wireline unit from the surface of the wellbore 101. The slicing tool BHA 150 (as seen in Figure 6(b)) comprises four main components, these being (from the in use top to bottom orientation or ends) as follows:- a) an upper anchor 152 which consists of an anchor body 154 which retains a plurality of equi-spaced slips 156 which are distributed around the circumference of the anchor body 154 and which can be actuated by any suitable means, such as an electric motor / hydraulic motor (not shown) or the like to be forced outwards through apertures formed in the anchor body 154 and against the inner surface of the throughbore 109T of the production tubing string 109 such that the slips 154 will grip the inner throughbore 109T and thereby anchor the slicing tool BHA 150 in place within the production tubing string 109. The operator can selectively control or actuate the upper anchor 152 from the surface of the wellbore 101 in order to actuate the slips between their unset configuration as shown in Figure 6(b) and their set configuration (such as that shown in for example Figure 6(d)) and vice versa. b) a stroker tool 160 which is formed in two telescopic parts, namely:- i) an upper stroker mandrel 162 which is secured to the lower end of the anchor body 154 of the upper anchor 152; and ii) a lower stroker lead screw 164, the lower end of which is attached to a lower anchor 170. Furthermore, the upper stroker mandrel 162 shown in the figures comprises a screw threaded inner bore 163 within which is located a screw threaded outer surface of the lower stroker lead screw 164. The stroker tool 160 is further provided with a motor such a suitable hydraulic or electrically operated motor which can rotate the lower stroker lead screw 164 relative to the upper stroker mandrel 162 and in so doing can move the lower stroker lead screw 164 axially (or vertically) relative to the upper stroker mandrel 162 and therefore can telescope the lower stroker lead screw 164 out and in relative to the upper stroker mandrel 162. It should be noted that the stroker tool 160 can be either:- i. an electrical motor powered stroker tool, where the electrical power is supplied from the surface via a power line (not shown) located within the wireline and which rotates the lower stroker lead screw 164 in either direction as required and instructed by the operator; or ii. a hydraulically powered piston and cylinder arrangement (not shown) – that is, the lower stroker 164 is instead in the form of a piston and which is not rotated but is simply telescopically stroked out and stroked in within the upper stroker mandrel 162 which is instead in the form of a cylinder (or vice versa). c) a lower anchor 170 which is very similar to the upper anchor 152 and where the lower anchor 170 also therefore comprises an anchor body 174 which is secured at its lower end to the upper end 182U of the slicer frame 182 of a blade tool 180 which will be described subsequently. In an alternative, less preferred embodiment, the anchor body 174 of the lower anchor 170 is secured at its upper end to the lower end 182U of the slicer frame 182 of a blade tool 180 (such that the blade tool 180 is located just above the lower anchor 170. Suitable examples of upper anchor 152, stroker tool 160 and lower anchor 170 include suitably modified (to make them longer because conventional stroker tools have a relatively short stroke) stroker tools such as those offered by the following companies:- Archer Wireline of Aberdeen, UK, such as:- or ii) Welltec of Aberdeen, UK, such as:- or iii) Schlumberger of Aberdeen, UK such as:- https: / / www.slb.com / - / media / files / wireline-production-services / product-sheet / resolve- iv) Altus Intervention of Portlethen, UK, such as:- https: / / www.altusintervention.com / resources / spec-sheets / precisionstroker It should be noted however that such conventional anchor and stroker tools are all relatively short and such modified anchor and stroker tools would likely be increased in length to provide in the region of between one foot and 32 feet or longer of stroke. Indeed, the longest current stroke available from conventional strokers is in the region of 8.5 feet, but it is preferred that the conventional stroker be modified to provide a longer stroke such as up to 30 feet of stroke in the preferred embodiments. It should also be noted that if the wellbore 101 is highly deviated, a conventional tractor (not shown) can be run in conjunction with the slicing tool BHA 150 (or the cutting and expansion BHA 250 to be described subsequently) in order to aid RIH, POOH and also operation thereof. Suitable examples of such a conventional tractor include those offered by the following companies:- i) Welltec of Aberdeen, UK, such as:- https: / / welltec.com / intervention / conveyance / or ii) Baker Hughes of Aberdeen, UK, such as:- slsh.pdf or iii) Altus Intervention of Portlethen, UK, such as:- Importantly, the slicing tool BHA 150 also comprises a fourth tool in the form of an embodiment of a blade tool 180 in accordance with the present invention at its lower end as will now be described. d) The blade tool 180 comprises (as shown in particular in Figures 6(j) and 6(k)), a slicer frame 182 the upper end 182U of which is securely mounted by, for example, welding to the lower end of the lower anchor 170 and, in particular, to the lower end of the lower anchor body 174. Furthermore, at least a pair of slicing blades 186 are pivotally mounted by means of retention pins 194 to either side of the slicer frame 182 such that the respective blades 186 can pivot about the retention pin 194 that affixes them to the slicer frame 182 between:- i) a closed (stowed) configuration as shown in, for example, Figure 6(j) and in which a blade knife surface 187 of the respective blades 186 (and indeed the majority or the whole of the respective blade 186) is substantially or wholly contained entirely within the slicer frame 182 and in particular the slicer blade carrier / outer housing 184 which surrounds the slicer frame 182 (to a sufficient extent such that the blade knife surface 187 does not make contact with the inner throughbore 109T of the production tubing string 109); and ii) an open (slicing) configuration as shown in for example Figures 6(g) and 6(i) in which each slicing blade 186 can project through a respective blade aperture 185 provided in the sidewall of the carrier / outer housing 184, such that when the slicing blades 186 are moved into the open configuration, the said blade knife surface 187 is rotated to project outwardly from the outer surface of the slicer blade outer housing 184 and through the blade apertures 185 such that the blade knife surface 187 of each slicing blade 186 is directed outwardly and upwardly and is preferably at an angle of approximately 45 degrees or in an upper hook shape to the horizontal plane. Alternatively, less preferred is an embodiment where the or each slicing blade comprises a circular blade (not shown) which is not powered as such but which rotates around a pivot pin (not shown) as it crawls upwards when the blade tool 180 is pulled upwards (by the operator operating the wireline unit at the surface to slowly reel in the wireline). In either embodiment, it is most preferred that the slicing blades 186 are non-powered (and this has the advantage of not requiring downhole power and / or a downhole motor which would otherwise be required to power a powered blade) but are rather pulled upwards to cut or slice through the production tubing string 109 by being secured to the blade tool 180 as it is pulled upwards (by the operator operating the wireline unit at the surface to reel in the wireline). Furthermore, the inner most end of each blade 186 is pivotally attached to a blade hinge plate 190 via a respective retention pin 194 and the blade hinge plate 190 is further coupled at its approximate mid-point to an actuating arm 188 which is further attached at its upper end via a screw thread 189 to the lower end of the lower stroker lead screw 164 (or one of a piston and cylinder if the stroker tool 160 is in the form of a cylinder and piston arrangement (not shown)). Accordingly, the slicing blades 186 can be moved between their closed (stowed) configuration as shown in Figure 6(f) (in which case their respective blade knife surfaces 187 are wholly or substantially contained within the slicer blade carrier / outer housing 184) and their open (slicing) configuration in which the blade knife surfaces 187 are wholly or substantially located outwith the slicer blade carrier / outer housing 184 as shown in Figures 6(g) and 6(i). Moreover, the slicing blades 186 are moved between the closed configuration shown in Figures 6(f) and 6(h) and the open configuration shown in Figures 6(g) and 6(i) by the actuating arm 188 being forced upwards (by the lower stroker lead screw 164 pulling it upwards) relative to the slicer blade frame 182. As will be discussed subsequently, this can only occur when the lower anchor 170 has been set against the inner surface of the throughbore 109T of the production tubing string 109. Figure 6(b) shows the slicing tool BHA 150 in the running in hole (RIH) position where the upper anchor is unset, the stroker tool 160 is wholly stroked in, the lower anchor 170 is unset and the blade tool 180 is in the slicing blade 186 closed (stowed) configuration. Stage 3 - Next stage of operation of slicing tool BHA 150 - Figure 6(c) In order to start the stage of operation, the stroker tool 160 of the slicing tool BHA 150 is actuated by the operator from the surface of the wellbore 101 to extend or stroke out to its maximum extent (in order to increase the distance between the upper anchor 152 and the blade tool 180 to the maximum extent which could – depending upon the requirements – be anywhere in the region of 1 foot to 32 feet but with conventional stroker tools 150 is typically in the region of 8.5 feet) and this configuration of the slicing tool BHA 150 is shown in Figure 6(c). That said, it is preferable that the stroker tool 150 will not be functioned to its full stroke but rather will only be stroked a majority of its full stroke such as 90% or 95% of its full stroke for example only stroked by 8 feet during this stage of operation and the final stroke such as the final 0.5ft will be used for contingency purposes for moving the stroker tool 150 downward for contingency / emergency release if needs be. Stage 4 - Next stage of operation of slicing tool BHA 150 - Figure 6(d) The next stage as shown in Figure 6(d), whereby the upper anchor 152 and lower anchor 170 are both actuated by the operator to set such that their respective slips 156 and 176 are actuated to move outwards through their respective anchor bodies 154, 174 such that the respective slips 156, 176 grip against and are secured against the inner surface of the throughbore 109T of the production tubing string 109. In doing so, the setting of the upper anchor 152 secures the slicing tool BHA 150 above the stroker tool 160 and the setting of the lower anchor 170 secures the slicing tool BHA 150 and in particular the blade tool 180 below the stroker tool 160. Stage 5 - Next stage of operation of the slicing tool BHA 150 – figure 6(e) The stroker tool 160 is then actuated by the operator from the surface to close by a relatively short stroke such as in the region of one quarter of an inch or so and because both upper anchor 152 and lower anchor 170 remain set, the lower stroker lead screw 164 is pulled upwards to stroke into the upper stroker mandrel 162 by that relatively short distance. This thus causes the actuating arm 188 to move upwards with the lower stroker lead screw 164 by the same amount of stroke and therefore the blade hinge plate 190 and thus the inner ends of the respective slicing blades 186 are also moved upwards and in doing so rotate the blade knife surfaces 187 of each of the blades 186 outwards until they reach the open (slicing) configuration / position shown in Figure 6(e) and in more detail in Figures 6(g) and 6(i). Moreover, the arrangement of the blade tool 180 is such that each of the slicing blades 186 will open substantially simultaneously, and thus the blade tool 180 has the advantage that the opening forces applied to the blade tool 180 are distributed substantially equally. An actuating arm stop 196 is secured to the actuating arm 188, where is projected through an arm slot 197 which is formed longitudinally along and through the sidewall of the slicer blade carrier / outer housing 184. Thus, the actuating arm slot 196 and therefore the actuating arm 188 can only move axially along the length of the arm slot 197 and therefore the distance of the said relatively short stroke is defined by the length of travel that the actuating arm stop 196 can travel within / along the arm slot 197. Furthermore, the length of the slicing blades 186 and therefore the length of the blade knife surfaces 187 is chosen such that they will pierce through and furthermore will project all the way through the sidewall of the production tubing string 109 and in doing so will slice through the said sidewall. Thus, the sidewall of the production tubing string 109 has been punctured by the slicing blades 186 and in particular by the blade knife surfaces 187. It should be noted that, if needs be, the operator can arrange to temporarily lock (e.g. by use of one or more shear pins (not shown)) the slicing blades 186 in the closed (stowed) configuration such that they remain in the closed (stowed) configuration during RIH if it turns out that the weight of the slicer blade frame 182 / lower anchor 170 results in the blade tool 180 trying to transition to the open configuration during RIH, with the shear pins being sheared during this stage 5. Stage 6 - Next stage of operation of the slicing tool BHA 150 – Figure 6(L) Once the operator has noted confirmation that the slicing blades 186 have fully pierced the sidewall of the production tubing string 109 (said confirmation being based on the blades 186 not being retracted during the slicing operations or alternatively, both anchors 152, 170 could be released and the slices in the sidewall of the production tubing string 109 could be drifted with the slicing blades 186 out i.e. running the slicing blades 186 up and down the slices through the sidewall of the production tubing string 109 & in doing so the operator will note there is very little friction occurring), the operator will, from surface, then actuate the bottom anchor 170 to unset in preparation for slicing a vertical length 109VS of the production tubing string 109 in the next stage below. Stage 7 - Next stage of operation of the slicing tool BHA 150 – Figure 6(m) As shown in Figure 6(m), the stroker tool 160 has been completely stroked in, in that the lower stroker lead screw 164 has been rotated to move upwards fully into the upper stroker mandrel 162 and in doing so has pulled the actuating arm 188, the blade hinge plate 190 and therefore the slicing blades 186 upwards and in doing so the blade knife surfaces 187 have sliced through and formed a vertical slice 109VS through the sidewall of the production tubing string 109, where the length of the vertical slice 109VS formed so far equals the length of the stroke of the stroker tool 160. Furthermore, and importantly, the vertical slices 109VS have been formed in the area of the production tubing string 109 adjacent to / in the same vertical location as the required logging area 125. Furthermore, because the slicer blade frame 182 is carried upon the retaining pins 194 which are connected to the slicing blades 186, the slicer blade frame 182 is therefore also pulled upwards as is the lower anchor body 170. Furthermore, because of the pivoted arrangement of the slicing blades 186, the reaction force of the sidewall of the production tubing string 109 being sliced by the blade knife surfaces 187 will actually try to force the slicing blades 186 further outwards and therefore reinforces the slicing blades 186 to be maintained in the open (slicing) configuration as shown in Figures 6(g) and 6(i), and therefore as shown in Figure 6(m). Stage 7(b) - Next stage of operation of the slicing tool BHA 150 is optional depending upon the operator preferred operational stages and / or the vertical length of slice required – Figure 6(n) If the length of the stroke of the stroker tool 160 in stroking in from the configuration shown in Figure 6(l) to the configuration shown in Figure 6(m) was not long enough (for example which may be in the region of 8 feet for a conventional stroker tool 160) then the operator can follow this optional step and set the lower anchor 170 and then unset the upper anchor 152, as shown in Figure 6(n). However, even if the length of the stroke of the stroker tool 160 in stroking in from the configuration shown in Figure 6(l) to the configuration shown in Figure 6(m) was not long enough, the operator could (if the wireline being used by the operator has a high enough tensile limit) also omit this stage 7(b) and instead maintain tension on the wireline at the surface during above stage 7 and instead simply unset the upper anchor 152 (leaving the lower anchor unset) and pull the slicing tool 150 upwards by means of increased tension exerted from surface on the wireline (by operating the wireline unit at the surface to reel in the wireline) to thereby take up the slack in the wireline and in that case the operator could move on to the next stage. However, that alternative approach suffers the potential disadvantage that the operator risks causing the blades 186 to swing back in to the closed (stowed) configuration if there is any unintended downward movement of the slicer blade frame 182 with respect to the slicer blades 186 which would mean that the vertical slices 109 VS may not be formed sufficiently in length. Stage 8 - Next stage of operation of the slicing tool BHA 150 - Figure 6(o) The operator can then actuate the stroker tool 160 to fully stroke out or fully open to its maximum telescopic extent and because the lower anchor 170 has been set, the upper anchor 152 is moved upwards, with the operator taking up any slack on the wireline back to the wireline unit (not shown) (by operating the wireline unit at the surface to reel in the wireline). As shown in Figure 6(o), the slicing blades 186 are retained in their open configuration. Stage 9 - Next stage of operation of the slicing tool BHA 150 – Figure 6(p) The operator will then actuate the upper anchor 152 to set against the inner surface of the throughbore 109T of the production tubing string 109 and the operator then further actuates the lower anchor 170 to unset and as shown in Figure 6(p), the slicing blades 186 continue to be retained in their open (slicing) configuration. The operator will then instruct the stroker tool 160 to stroke inwards such that it moves between the configurations shown in Figure 6(p) and the next stage of operation as shown in Figure 6(q) until it is fully stroked in as shown in Figure 6(q). Stage 10 - Next stage of operation of the slicing tool BHA 150 – Figure 6(q) Due to the actuation of the stroker tool 160 to stroke inwards until it is completely stroked inwards as shown in Figure 6(q) discussed immediately above, the slicing blades 186 have been pulled upwards toward the upper anchor 152 in their open (slicing) configuration and in so doing have created a further vertical slice 109VS through the sidewall of the production tubing string 109 and have therefore further increased the length of the vertical slice 109VS through the said sidewall. The next stage as shown in Figure 6(q) involves the operator actuating the lower anchor 170 to set. It should be noted that Stages 7(b) to 10 may be optional if the first slices formed (from stage 5 (figure 6(e)) to stage 6 (figure (L)) provide a sufficiently long vertical slice 109VS. Alternatively, if the operator requires to continue to form a longer vertically slice 109VS through the sidewall of the production tubing string 109 to thereby increase the length of the vertical slices 109VS, then the operator can repeat the steps as shown in Figures 6(n) to 6(q) and as described in stages 7(b) to 10 above once through or indeed as many times through as required until the required length of vertical slice 109VS through the production tubing string 109 sidewall has been achieved. When that occurs, the operator can then start the process to remove the slicing tool BHA 150 from the wellbore 101 (by operating the wireline unit at the surface to reel in the wireline) and this is described in the next stage of operation of the slicing tool BHA 150. The skilled person will however realise that whilst it is described herein that the vertical slice 109VS is formed in the vertical direction, that vertical direction of the slice need not be straight and / or parallel to the longitudinal axis of the production tubing string 109 but rather could be in a different direction such as a helical shaped slice extending generally along and part circumferentially around the longitudinal axis of the production tubing string 109. Stage 11 - Next stage of operation of the slicing tool BHA 150 – Figure 6(r) The operator will then operate the stroker tool 160, whilst both upper anchor 152 and lower anchor 170 are set, to open or stroke out the stroker tool 160 by a relatively short distance such as in the region of one quarter inch or so and in so doing will move the actuating arm 188 downwards by that distance of stroke (such as one quarter inch or so) and in so doing move the blade hinge plate 190 downwards by that distance as well and in so doing move the inner ends of each of the slicing blades 186 downwards by that stroking distance which will swing the outer most ends of the slicing blades 186 inwards such that the whole length or the substantial length of the blade knife surfaces 187 are moved wholly within or substantially within the slicer blade carrier / outer housing 184 such that they are radially spaced apart from, and therefore will not make contact with, the inner surface or throughbore 109T and thus the sidewall of the production tubing string 109. The operator can then actuate the lower anchor 170 to unset and also actuate the upper anchor 152 to unset. The slicer tool BHA 150 is now in the configuration shown in Figure 6(r) and is ready to be, and is, pulled out of the hole (POOH) by the operator winding in the wireline at the surface on the wireline unit to thereby wind in the wireline onto the reel of the wireline unit. The production tubing string 109 now comprises the vertical slices 109VS formed vertically along its axial length for a distance that approximately corresponds to the vertical length of the required logging area 125, and in practice that is likely to be as long a distance as possible between a pair of collars 126 such as in the region of 32 feet to 42 feet in length. Stage 12 - Next stage of operation – running in the cutting and expansion BHA 250 in the RIH position – Figure 7(a) and 7(b) The third main part of the method in accordance with the present invention (the first being the running in of the bridge plug 130, the second being the running in and operation of the slicing tool BHA 150) can now commence and mainly consists of the running in of a cutting and expansion BHA 250 as shown in the running in position (RIH) in Figure 7(b). The cutting and expansion BHA 250 can be run in on any suitable conveyance means but is preferably run in on wireline (not shown) using a wireline unit from the surface of the wellbore 101. The cutting and expansion BHA 250 comprises five main components (not all of which are essential), these being (from the in use top to bottom orientation or ends) as follows:- a) an anchor 252 at its upper end (which is similar to the upper anchor 152 of the slicing tool BHA 150) which is secured at its lower end to the upper end of a stroker tool 260; b) a stroker tool 260 (which is similar to the stroker tool 160 of the slicing tool BHA 150) which is secured at its lower end to the upper end of a tubing cutter tool 273; It should be noted that the anchor 252 and the stroker tool 260 can be any suitable anchor and stroking tools and suitable examples of anchor 252 and stroker tool 260 include suitably modified (to make the stroker tool 260 longer if necessary because conventional stroker tools have a relatively short stroke) stroker tool 260 such as those offered by the following companies:- i) Archer Wireline of Aberdeen, UK, such as:- slickline-services / welldrone-tractor-msp / ii) Welltec of Aberdeen, UK, such as:- iii) Schlumberger of Aberdeen, UK such as:- iv) Altus Intervention of Portlethen, UK, such as:- It should also be noted that the stroker tool 260 can be optional as to whether it is included or not in the cutting and expansion BHA 250 and it can be omitted particularly if the cutting and expansion BHA 250 is to be run into a substantially vertical and / or relatively shallow wellbore 101 – and particularly if a tractor unit (not shown) such as a tractor unit such as those offered by the following companies:- i) Welltec of Aberdeen, UK, such as:- https: / / welltec.com / intervention / conveyance / or ii) Baker Hughes of Aberdeen, Scotland, such as:- https: / / www.bhge.com / system / files?file=2019-04 / SondeTrax-wireline-deployment-tractor- slsh.pdf or iii) Altus Intervention of Portlethen, UK, such as:- is used instead of the stroker tool 260. c) a tubing cutter tool 273 which secured at its lower end to the upper end of a spacer rod 279. The tubing cutter tool 273 can be any suitable tubing cutter tool such as:- i) A tubing cutter offered by Welltec of Aberdeen, Scotland such as:- or ii) A tubing cutter offered by Halliburton of Aberdeen, UK such as:- perforating_public or iii) A tubing cutter offered by Baker Hughes of Aberdeen, UK such as:- slsh.pdf Other suitable tubing cutter tools 273 could be used; d) a spacer rod 279 which is secured at its lower end to the upper end of an expansion tool 280. The spacer rod 279 is any suitable spacer rod of a predetermined length and is typically a length of tubular offered by many different downhole tool companies, where the predetermined length is chosen so that the spacer rod 279 is slightly longer than the length of the vertical slice 109VS previously formed. For example, if the operator required to form a 32 foot length vertical slice 109VS through the sidewall of the production tubing string 109, then the spacer rod 279 will typically be slightly longer than 32 feet, such as for example 33 feet in length and that length is predetermined by the operator prior to running the cutting and expansion BHA 250 into the wellbore 101 and is predetermined so that the distance between the upper end of the expansion tool 280 and the lower end of the tubing cutter tool 273 is slightly longer than the vertical length of the vertical slice 109VS formed through the sidewall of the production tubing string 109; and e) an expansion tool 280, embodiments of which described herein are in accordance with a further aspect of the present invention. The expansion tool 280 is shown in more detail in Figures 8(c) to 8(i) and comprises an outer body 282 which is generally cylindrical and which has apertures or exit holes 284 formed therein through its sidewall around its approximate mid-point. The expansion tool 280 further comprises a longitudinally extending compression rod 286 located on and moveable longitudinally along the longitudinal central axis of the outer body 282 and which is further telescopically moveable within the outer body 282 along its longitudinal axis. The lower end of the compression rod 286 is provided with a flange 287 and which, in use, forms the lowest end of the cutting and expansion BHA 250 and can be used by the operator to land against the upper surface of the bridge plug 130 in order to actuate the expansion tool 280 as will be described subsequently, in order to provide a relatively simple but effective means of actuating the expansion tool 280. The upper end of the compression rod 286 is secured to the lower end of a plurality of expansion leafs 288 and which generally are formed of rectangular (or similar) strips of spring metal or other suitable resilient material and which can be secured for instance by welding to the upper end of the compression rod 286 and more particularly extend upwards and outwards from the outer circumference of the upper end of the compression rod 286 and which have their lower ends equi-spaced around the outer circumference of the upper end of the compression rod 286. The upper section of the plurality of expansion leafs 288 are arranged such that they are bent backwards upon themselves such that they generally curve in an arc through 180 degrees until they project out through the sidewall of the outer body 282 through their respective exit holes 284 and the outer most ends of the expansion leafs 288 are secured to the outer lower end of the outer body 282 by means of shear screws or shear pin retainers 289 (particularly shown in Figure 8(d)). A reactive spring retainer 290 which is preferably wedge shaped with the wedge shape being provided on its lower surface so that it is in contact with the upper surface of the expansion leafs 288 at their approximate uppermost (mid-point) end as they curve around back on themselves is located within the inner throughbore of the outer body 282 and is in contact with the upper surface of the uppermost (mid- point) end of the expansion leafs 288. The upper surface of the reactive spring retainer is in contact with the lower end of one of or both of a reactive piston 292 and / or a reactive spring 294 such as a coiled spring 294 and either one or both of the reactive piston 292 and reactive spring 294 have their upper end in contact with the inner upper end of the outer body 282, such that movement of the reactive spring retainer 290 upwards will compress either or both of the reactive piston 292 and reactive spring 294 in order to store energy therein. The reactive piston 292 mainly acts to retain the reactive spring 294 centralised but the reactive piston 292 can also be used for piston force if required. The outer surface of the compression rod 286 is preferably provided around its approximate mid-point with one or more locking dogs 296 which, as will be described subsequently, can be located and secured within locking dog locator recesses 283 provided at or toward the lower end of the outer body 282 in order to lock the compression rod 286 in its locked position as shown in Figures 8(c) in the middle upper and lower drawings and also in the right hand upper and lower drawings of Figure 8(c). The expansion tool 280 is arranged such that movement of the compression rod 286 from :- i) the fully stroked out configuration (referred to below as the run in hole (RIH) configuration 280RIH) shown in the left hand upper and lower drawing shown in Figure 8(c); to ii) the fully stroked in but compressed configuration (referred to below as the compressed configuration 280C) shown in the middle upper and lower drawing shown in Figure 8(c) compresses the expansion leafs 288 and the reactive piston 292 and / or the reactive spring 294; and ultimately to iii) the fully stroked in but expanded configuration (referred to below as the expanded configuration 280C) shown in the right hand upper and lower drawings in Figure 8(c) in which the expansion leafs 288 are able to expand outwards as shown in the upper right and lower right drawings of Figure 8(c) in order to expand the cut section of the production tubing string 109 as will be described subsequently. The cutting and expansion BHA 250 could also optionally be provided with a weight bar (not shown) in order to provide additional weight to the cutting and expansion BHA 250 to aid RIH and / or tagging of the compression rod 286 if required. As shown in Figure 7(b), the expansion tool 280 is run into the hole on the cutting and expansion BHA 250 with the compression rod 286 in the fully stroked out configuration as shown in the upper left and lower left drawings of Figure 8(c) and thus neither of the expansion leafs 288, reactive piston 292 nor the reactive spring 294 are compressed to any significant extent. The cutting and expansion BHA 250 is run into the wellbore 101 on a suitable conveyance means such as wireline and is lowered into the wellbore 101 through the production tubing string 109 until the lower flange 287 of the expansion tool 280 makes contact with the upper surface of the bridge plug 130. Stage 13 - Next stage of operation of the cutting and expansion BHA 250 – Figure 7(c) The operator will note the weight on the wireline starting to reduce and will now slowly lower the wireline and in doing so the weight of the cutting and expansion BHA 250 will start to be taken up on the flange 287 and compression rod 286 which will force the compression rod 286 upwards into the throughbore of the outer body 282 and in so doing will force the expansion leafs 288 upwards which in turn will compress against the reactive spring retainer 290 (particularly because the outer ends of the expansion leafs 288 cannot expand outwards because at this point they will still be located within the relatively confined throughbore 109T of the (uncut) lower section 109L of the production tubing string 109. Thus, the reactive spring retainer 290 will be forced upwards from the position shown in the upper left and lower left drawings of Figure 8(c) toward the upper end but within the outer body 282 and in doing so will compress both the reactive piston 292 and the reactive spring 294 (if both are present) in order to store compressive energy therein and the expansion tool is now in the configuration shown in the middle upper and middle lower drawings of Figure 8(c) and is therefore in the compressed configuration. The expansion tool 280 has thus been actuated and is in the configuration now shown in Figure 7(c). Stage 14 - Next stage of operation of the cutting and expansion BHA 250 – Figure 7(d) The operator will then lift the cutting and expansion BHA 250 with the wireline at surface and will receive confirmation that the expansion tool 280 has been actuated into the compressed configuration 280C due to increased resistance being observed due to the friction occurring due to the contact between the outer surface of the expansion leafs 288 and the inner throughbore 109T. The tubing cutter tool 273 is then actuated from the surface of the wellbore 101 by the operator to engage its cutting elements such as cutting arms 274 with the inner throughbore surface 109T of the production tubing string 109 by for example rotating or radially extending the cutting arms 274 outwardly away from the cutter tool body 275 (although that of course depends on the particular type of tubing cutter tool 273 used). The cutting arms 274 can then be actuated to provide a horizontal cut through the sidewall of the production tubing string 109 at the location #A at the lower end of the vertical slices 109VS (i.e. the cutting arms 274 cut all the way through the sidewall 360 degrees around the circumference of the sidewall on a plane which is substantially perpendicular to the longitudinal axis of the production tubing string 109 at the location #A such that the production tubing string 109 is severed at that location #A into two parts 109U; 109L) such that the lower end of the vertical slices 109VS are freed from what is now the upper end of the lower section 109L of the production tubing string 109 such that the vertical tubing slices 109VS are only now attached to the lower end of the upper section 109U of the production tubing string 109 and therefore the vertical tubing slices 109VS are castellated in shape extending downwardly from the lower end of the upper section 109U. The production tubing string 109 is now in the configuration shown in Figure 7(e) with the bridge plug 130 still set, the vertical tubing slices 109VS created and the production tubing 109 has been horizontally cut at the lower end of those vertical tubing slices 109VS at location #A. In addition, the expansion tool 280 is still located in the lower section 109L of the production tubing string 109 above the upper end of the bridge plug 130. The operator will then, if possible, actuate the tubing cutter tool 273 to close the cutter arms 274 by radially withdrawing them into their recesses within the cutter tool body 275 such that they are flush with the outer surface of the cutter tool body 275 as shown in Figure 8(b). However, it is possible in some circumstances that the cutter arms 274 may become trapped between the upper 109U and lower 109L sections of the production tubing string; this could occur because there is a risk of the production tubing string 109, which up until that point has been held in compression due to the weight of the string 109 above, relaxing and the cutting arms 274 could become trapped in between the lower end of the upper section 109U and the upper end of the lower section 109L. If that occurs, the operator can pull up on or overpull the wireline at the surface in order to pull the cutting and expansion BHA 250 upwards and in doing so can shear shear pins (not shown) which attach the cutting arms 274 to the cutter tool body 275 in order to shear off the cutting arms 274 and the cutting tool BHA 250 can be POOH and a new cutting tool BHA 250 (with a new set of cutting arms 274 attached) can be RIH instead, in order to perform the next cut at location #B which will be described subsequently. Stage 15 - Next stage of operation of the cutting and expansion BHA 250 – Figure 8(a) The operator now desires to expand the lower, free ends of the vertical tubing slices 109VS outwards as shown in Figure 8(a). This is achieved particularly for substantially vertical wellbores 101, by the operator, after completing the horizontal cut through the sidewall of the production tubing string 109 at location #A, picking the wireline up at the surface by reeling in the wireline unit and thereby lifting the cutting and expansion BHA 250 upwards until the expansion tool 280 is located just within the upper section 109U of the production tubing and therefore is clear of the lower section 109L of the production tubing string. The operator will know this has occurred due to the resistance having disappeared due to the contact between the outer surface of the expansion leafs 288 and the inner throughbore 109T having been removed because the expansion tool 280 is now located above the cut at location #A. Accordingly, because the expansion leafs 288 are now free of being confined within the fixed inner throughbore of the production tubing string 109 within the lower section 109L thereof, the portion of the expansion leafs 288 which are located outside of the outer body 282 will be able to expand outwards due to being forced outwards by the piston 292 and / or the spring 294 seeking to unload and will therefore move from the compressed configuration 288C shown in the upper middle and lower middle drawings of Figure 8(c) to the radially expanded outwards configurations 288E shown in the upper right and lower right drawings of Figure 8(c). In other words, the expansion leafs 288 will move from their compressed configuration 288C shown in the middle drawings into their expanded configurations 288E as shown on the right hand drawings of Figure 8(c). Thus, the expansion leafs 288 in their expanded configurations 288E will expand the lower free ends of the vertical tubing slices 109VS outwards into the splayed out configurations shown in Figure 8(a) such that the lower free ends now have a wider internal diameter than the outer diameter of the lower section 109L of the production tubing string 109. Alternatively, if the wellbore 101 is highly deviated and / or substantially horizontal, the operator can (instead of lifting up the cutting and expansion BHA 250 at the surface with the wireline unit) actuate the upper anchor 252 to set and can then use the stroker tool 260 to stroke in, thereby pulling the expansion tool towards the stroker tool 260 and anchor 252 in order to expand the lower free ends of the vertical tubing slices 109VS outwards into the splayed out configurations shown in Figure 8(a) such that the lower free ends now have a wider internal diameter than the outer diameter of the lower section 109L of the production tubing string 109. The cutting and expansion BHA 250 is now in the position and configuration shown in Figure 8(b) and the production tubing string 109 is now in the configuration shown in Figure 8(a), and the tubing cutter tool 273 (and more importantly the tubing cutting arms 274 thereof) are now located in the region of 33 feet above the cut location #A. Stage 16 - Next stage of operation of cutting and expansion BHA 250 – Figure 9(a) After the operator has received confirmation of the vertical tubing slices 109VS as having been expanded (due to the aforementioned reduction in resistance being noted), the operator will actuate the anchor 252 to set against the inner surface of the throughbore 109T of the upper section 109U of the production tubing string 109 at a location such that the tubing cutter tool 273 and in particular the tubing cutting arms 274 are aligned with a location #B within the production tubing string 109, where location #B is located just above, for example one foot above, the upper end of the vertical tubing slices 109VS (and this has the advantage that – once the cut has been made at location #B as will be described subsequently - the individual cut vertical slices 109VS will stay connected at their upper end and won’t all separately fall down the wellbore 101). The operator will then actuate the tubing cutter tool 273 to rotate or radially expand the cutting arms 274 outwards from the cutter tool body 275 and the operator will actuate the tubing cutting tool 273 to form a horizontal cut through the sidewall of the production tubing string 109 at location #B as shown in Figure 9(c). Accordingly, the vertical tubing slices 109VS section of the production tubing string 109 is now completely separated from both the lower section 109L and the upper section 109U of the production tubing string 109. Optionally, after the operator has performed the second cut at location #B, the operator can retract the cutting arms 274 inwards into their respective recesses in the cutter tool body 275 and lift the cutting and expansion BHA 250 upwards, such that the expansion tool 280 will continue to expand the rest of the vertical tubing slices 109VS outwards from their lower end upwards. Stage 17 - Next stage of operation of cutting and expansion BHA 250 – Figures 10(a) and 10(b) – pushing the cut section 109VS of production tubing string 109 into the annulus 300 The operator now wishes to move the cut section 109VS of the production tubing string 109 into the annulus 300, where the annulus 300 is the area between the outer surface of the lower section 109L of the production tubing string 109 and the inner surface of the casing 103 (so that the logging tool (not shown) that will be subsequently run (see Figure 12) can directly access the inner surface of the casing 103 in order to log the required logging area 125). The goal of the operator during this stage is to move the cut section of tubing 109VS to the position shown in Figure 10(a) and the operator achieves that by lowering the cutting and expansion BHA 250 within the wellbore 101, by slacking off weight on the wireline at surface (i.e. by further RIH) but with the cutting arms 274 (still) extended radially outwards such as the configuration shown in Figure 10(b) and in that manner, the outer ends of the cutting arms 274 will push against the upper surface of the cut section 109VS of the production tubing string 109 and will force the cut section 109VS downwards within the wellbore 101 such that the splayed outer lower ends of the cut section 109VS will pass over the upper end of the lower section 109L of the production tubing string 109 such that the cut section 109VS moves from the position / configuration shown in Figure 10(c) until it arrives in the configuration shown in Figures 10(a) (and in more detail in Figure 10(d)) such that a reasonable length such as 30-32 feet or so of the cut section 109VS is now located over the upper end of the lower section 109L. In addition, the expansion leafs 288 are designed at their outer most sides to fold inwards so that the expansion tool 280 can pass into and down the throughbore 109T of the lower section of the production tubing string 109. The skilled person will also realise that if there is any difficulty encountered when using weight (i.e. when slacking off weight on the wireline at surface) and / or using gravity to guide or move the cut section of tubing 109VS into the annulus section 300, the operator could set the upper anchor 252 and the slices of the cut section 109VS of the production tubing string 109 could be pushed into the annulus section 300 using the extended cutting arms 274 of the stroker 260. Therefore a 30-32 feet section of the production tubing string 109 has been removed (i.e. there is now a 30-32 feet section of the production tubing string 109 that is open) to thereby provide a 30-32 feet section or so of the casing 103 at the required logging area 125 which can now be accessed by a logging tool (not shown) that can be run into the wellbore 101 through the upper section 109 and out of the lower end thereof and can therefore be clearly logged by the operator. Stage 18 - Next stage of operation of cutting and expansion BHA 250 – Figure 11 – cutting and expansion BHA 250 is POOH The operator will now remove and pull the cutting and expansion BHA 250 out of the hole and in order to do so, the operator will actuate the tubing cutter tool 273 to retract the cutting arms 274 toward the cutter tool body 275 until they are retained within their respective recesses within the cutter tool body 275. The cutting and expansion BHA 250 is now in the configuration shown in Figure 11 and is ready to be pulled out of hole by the operator. The operator can therefore operate the wireline unit at the surface of the wellbore 101 to raise the cutting and expansion BHA 250 upwards and pull it up to surface. In order to assist the operator POOH the cutting and expansion BHA 250 upwards and pull it up to surface, it should be noted that the expansion tool 280 is provided with a further feature to enable the expansion tool 280 to re-enter the upper section 109U of the production tubing string 109 and to reduce the friction between the expansion leafs 288 and the inner surface of the throughbore 209T of the upper section 109U. This reduction in friction feature is provided by the shear pins / screws 289 being arranged to be sheared or otherwise broken at a particular force level that is sufficient to not shear when the expansion leafs 288 are required to expand the lower ends of the vertical slices 109VS but will shear when the force acting upon the angled upper section 288AU of the expansion leafs 288 makes contact with the lower open end of the upper section 109U of the production tubing string 109. Accordingly, once the shear pins / screws 289 have sheared (i.e. when the operator POOH the cutting and expansion BHA 250 upwards and it re-enters the upper section 109U of the production tubing string 109), the lower outer ends of the expansion leafs 288 are free and can therefore much more easily be compressed by the inner throughbore 109T of the upper section 109U and will thus reduce the friction that occurs between the expansion tool 288 and the inner throughbore 109T and that could otherwise be significant particularly if the upper section 109U is relatively long (e.g. it could be up to 10,000 feet or even 15,000 feet or more in length). The cutting and expansion BHA 250 is thus pulled out of the wellbore 101 to the surface by the operator. In addition or alternatively, the one or more locking dogs 296 can be secured to the compression rod 286 by respective shear pins or other frangible devices such that the said shear pins can be sheared (in order to allow the leafs 288 to relax) by tagging flange 287 of the compression rod 286 against the upper surface of the bridge plug 130 if the operator can’t pull the expansion tool 280 through the lower end of the upper section 109U. Stage 19 - Next stage of operation – logging the required logging area – Figure 12 The wellbore 101 can now be logged by the operator running in any suitable conventional logging tool (not shown) into the required logging area 125 and the logging tool can thus have direct access to the inner surface of the casing 103 at that required logging area 125. Stage 20 - Next stage of operation – pumping a through tubing abandonment plug – Figure 13 Once the logging tool has been pulled out of wellbore 101, the operator can then install a packer (not shown but which may be an EZSV packer offered by Halliburton (www.Halliburton.com) of Aberdeen, UK for example) with an oscillator tool (such as an NOV Oscillator tool offered by NOV of Kintore, UK for example) and such an arrangement would act as an agitator when fluid and cement is being pumped (as will be described subsequently) and this is a standard practice downhole (and is similar to what is conducted on building sites when pouring cement to aerate the cement (i.e. ensure no air is trapped within the cement). The wellbore 101 is then ready for the operator to displace solvent wash spacers and place an approximate 1,500ft (in height) abandonment cement plug 127 by pumping down an abandonment plug 127 such as a section of cement and advantageously the operator can pump that through the upper section 109U of the production tubing string 109 and the operator will continue pumping until the required volume of abandonment plug 127, such as cement or other suitable material, has been delivered out of the bottom end of the upper section 109U of the production tubing string 109 in order for the operator to be able to form the casing hole abandonment plug 127 (as shown in Figure 13) within the casing at and likely above the required logging area 125 in order to form the abandonment cement plug 127 (which, as stated above) could be in the region of approximately 1500 ft in height but that could be shorter or longer as required). It should be noted however that other methods and apparatus to plug the wellbore may be used instead of cement such as other suitable plugging materials and such suitable plugging materials can include meltable and thereafter settable materials such as metal alloys (such as a Bismuth alloy offered by Wellstrøm (of Vesthagen 4, 4344 Bryne, Norway – www. wellstrom.com) could be used which, when set after melting with a heater element, will plug the wellbore. A further advantage of leaving the upper section 109U of production tubing string in place is that the operator can pressure test the abandonment cement plug 127 down through the upper section 109U in order to provide further confidence that a high quality permanent abandonment barrier 127 has been formed. Finally, the operator can arrange to cut the upper section 109U of the production tubing string 109 and the uppermost 10 feet or so of casing 103 just below the surface 114 (i.e. the production tubing string 109 is cut above the TRSSSV 116). Moreover, because only a small section (10 feet or so) of the production tubing string 109 and casing 103 needs to be cut and retrieved from the very upper most sections thereof at the surface 114, a small unit jacking unit only is required to pull the aforementioned relatively small lengths of cut production tubing string 109 and casing 103. Moreover, for the most part, the various stages of the embodiments in accordance with the present invention as described above can be completed using mainly / only a wireline unit and pumps. Thus, with embodiments of the present invention having the very large advantage that the upper section 109U of the production tubing 109 can be left within the wellbore 101 when the wellbore 101 has been plugged and abandoned, the operator will have experienced a significant shorter plug and abandonment operation and will also incur much lower costs (both capital and environmental costs) in doing so in terms of both equipment and personnel. TECHNICAL BENEFITS REALISED WHICH RESULT FROM EMBODIMENTS OF THE PRESENT INVENTION COMPARED WITH CURRENT TECHNOLOGY ^ Reduced environmental carbon footprint due the requirement for less auxiliary equipment; ^ Reduced environmental waste enabled by leaving the casing 103 and production tubing string 109 in the wellbore 101; ^ Reduced over abandonment liabilities cost; ^ No expensive drilling / workover unit required; ^ All activities can be conducted off of the critical path if required; ^ If no annular isolation is found or located, the embodiments of methods described herein will de-risk the future operations;. ^ Less manual handling of equipment required, and also all equipment utilised in the aforementioned embodiments is smaller scale than standard conventional abandonment methodology; and ^ Reduced personnel for the execution of the embodiments of methods described herein, for example:- o An average conventional drilling unit requires 32 people to work offshore on it and an execution time average from 25-31 days; whereas o It is envisaged that embodiments of methods described herein will likely require an average number of 16 people to work offshore on it and an execution time between 16 to 21 days, resulting in significant manpower costs and consequent reductions in risk to the personnel not required The proposed method provides a fully-rigless means of providing through-tubing 109 access to a wellbore 101 to permit verification of the annular barrier (cement) 107 and the full abandonment isolation of a reservoir interval or flow zone. This permits the full abandonment of suitable wells 101 with a reduced amount of auxiliary equipment and without the need of a rig: for the most part operations can be conducted using simply a wireline unit, pump and a fluid handling / cementing spread. It is estimated that for suitable well candidates, the aforementioned Cut & Drop method may be able to reduce the cost of well abandonment by as much as 80% and hence represents a potential step change in cost efficiency. Embodiments of the present invention can be modified or improved without departing from the scope of the invention. For example, it is preferred that the vertical slices 109VS are formed in the sidewall of the production tubing string 109 prior to both of the horizontal cuts being performed (firstly at location #A and secondly at location #B) and this has the advantage that the vertical slicing tool BHA 150 doesn’t need to be run into the inner throughbore 109T of the production tubing string 109 which has already had horizontal cuts provided at locations #A and #B (which would then complicate creating the vertical slices 109VS). However, in a less preferred embodiment, the horizontal cuts could be performed (firstly at location #A and secondly at location #B) first (i.e. by performing the appropriate stages of RIH, actuation and POOH of the cutting and expansion BHA 250), followed by the vertical slices 109VS being formed in the sidewall of the production tubing string 109 in between the two horizontal cuts (i.e. by performing the appropriate stages of RIH, actuation and POOH of the slicing tool BHA 150). Also, if an operator desired, they could use an elongate member other than wireline to deploy / run in the tools (i.e. the slicing tool 150 and / or the cutting and expansion BHA 250 disclosed above) – for example they could use coiled tubing or even a drill pipe string as the deployment / running in means instead of wireline but that is less preferred (because an operator will then require to use a drilling rig and that is considerably more complex and expensive).

Claims

CLAIMS:- 1. A method of removing a section of conduit from a wellbore, the method comprising:- i) running in a mechanical cutting tool assembly into the wellbore and actuating the mechanical cutting tool assembly to create at least one substantially vertical cut in the sidewall of at least a section of the vertical length of the conduit; ii) running in a cutting and expansion assembly into the wellbore and actuating the cutting and expansion assembly to firstly cut the conduit at or close to one end of the substantially vertical cut in the sidewall and secondly at or close to the other end of substantially vertical cut in the sidewall with substantially horizontal cuts in order to create:- an upper section, a lower section spaced apart from the upper section; and a cut section of the conduit with the substantially vertical cuts in the sidewall substantially contained therein; iii) expanding at least a portion of the length of the said cut section such that at least the said portion of the length of the cut section has a greater internal diameter than the outer diameter of at least one of the upper section and the lower section; and iv) at least one of moving or permitting to move the cut section within the wellbore in order to create a gap in the conduit between the upper section and the lower section.

2. A method according to claim 1, wherein the method is conducted in the following order of steps:- a first part of step ii) is conducted whereby the cutting and expansion assembly is actuated to firstly cut the conduit at or close to one end (preferably an upper end) of the substantially vertical cut in the sidewall to create a substantially horizontal cut preferably at or towards the top of the cut section; step iii) is then conducted to expand at least a portion of the length of the said cut section; and a second part of step ii) is then conducted whereby the cutting and expansion assembly is actuated to secondly cut the conduit, at or close to the other end ofsubstantially vertical cut in the sidewall, with a substantially horizontal cut preferably at or towards the bottom of the cut section.

3. A method according to either of claims 1 or 2, further comprising the step of:- v) at least one of quantifying and / or qualifying a barrier in the wellbore.

4. A method according to any preceding claim, further comprising the step of:- vi) placing and / or installing a wellbore barrier in the wellbore.

5. A method according to any preceding claim, wherein the conduit in the wellbore is a production tubing string and the method is a method of plugging and abandoning a wellbore through the production tubing string.

6. A method according to any preceding claim, wherein the mechanical cutting tool assembly comprises a mechanical cutting implement incorporating a mechanical blade actuable to slice through the conduit and the method further comprises running in the mechanical cutting tool on an elongate member into the conduit of the wellbore and actuating the mechanical cutting tool assembly to move the mechanical blade vertically with respect to the static conduit in the wellbore in order to create at least one substantially vertical and continuous cut in the sidewall of at least a section of the vertical length of the conduit.

7. A method according to any preceding claim, wherein the mechanical cutting tool assembly comprises a mechanical blade and which is moved axially within the production tubing string such that a vertical cut, of greater length than the length of the mechanical blade, is formed through the sidewall of the production tubing string; and the method further comprises:- actuating the mechanical cutting tool assembly to stop cutting through the sidewall of the production tubing string; and pulling the mechanical cutting tool assembly out of the production tubing string and out of the wellbore prior to performing step ii).

8. A method according to any preceding claim, wherein the method further comprises providing the mechanical cutting tool assembly with:-a pair of anchors, each anchor being selectively actuatable to set against and secure the respective anchor against the inner throughbore of conduit; and a telescopically arranged stroking tool, located in between the said pair of anchors, and being actuatable to stroke outwards to increase the distance between the said pair of anchors and stroked in to decrease the distance between the two anchors.

9. A method according to claim 8, further comprising:- a) actuating the stroker tool to stroke outwards to increase the distance between the pair of anchors such that there is an upper and a lower anchor; b) actuating one of the anchors to set; c) one of opening or closing the stroker tool to stroke the stroker tool to move the cutting blades vertically to form a vertical cut through the sidewall of the production tubing string.

10. An apparatus for removing a section of conduit from a wellbore, the apparatus comprising:- i) a mechanical cutting tool assembly capable of being run into the wellbore and further capable of being actuated to create at least one substantially vertical cut in the sidewall of at least a section of the vertical length of the conduit; ii) a cutting and expansion assembly capable of being run into the wellbore and further capable of being actuated to firstly cut the conduit at or close to one end of the substantially vertical cut in the sidewall and secondly at or close to the other end of substantially vertical cut in the sidewall with substantially horizontal cuts in order to create:- an upper section, a lower section spaced apart from the upper section; and a cut section of the conduit with the substantially vertical cuts in the sidewall substantially contained therein; such that at least a portion of the length of the said cut section has a greater internal diameter than the outer diameter of at least one of the upper section and the lower section, and such that the cut section can be moved within the wellbore in order to create a gap in the conduit between the upper section and the lower section.

11. An apparatus according to claim 10, wherein the mechanical cutting tool assembly further comprises a pair of anchors, each being selectively actuatable to set against and secure the anchor against the inner throughbore of the conduit; and a telescopically arranged stroking tool, located in between the said pair of anchors, and being actuatable to stroke outwards to increase the distance between the said pair of anchors and stroked in to decrease the distance between the two anchors.

12. An apparatus according to either of claims 10 or 11, wherein the mechanical cutting tool assembly further comprises at least one cutting blade; wherein the at least one cutting blade is capable of being actuated between a closed configuration in which it is spaced apart from the throughbore of the conduit and an open configuration in which it makes contact with and is capable of cutting through the sidewall of the conduit.

13. An apparatus according to either of claims 11 or 12, wherein the at least one cutting blade is a static blade comprising a cutting blade edge and which is arranged to slice through the sidewall of the conduit as the cutting blade edge is moved vertically along the length of the section of the conduit to be cut, such that the slicing action is wholly provided by the relative vertical movement between the cutting blade edge of the cutting blade and the sidewall of the conduit.

14. An apparatus according to claim 13, wherein the cutting blade is arranged such that the greater the slicing force the cutting blade is applying to the sidewall of the production tubing string, the greater the force keeping the cutting blade in the open configuration.

15. An apparatus according to any of claims 12 to 14, wherein the at least one cutting blade is pivotally mounted to a frame member of the mechanical cutting tool assembly by means of a respective pin member such that the respective cutting blade is pivotable about the pin member:- i) a closed (stowed) configuration in which a slicing edge of the cutting blade is at least substantially contained within the frame member such that the slicing edge of the blade knife surface is spaced apart from the inner throughbore of the conduit; andii) an open (slicing) configuration in which the cutting blade can project outwards from the mechanical cutting tool assembly, such that when the cutting blade is moved into the open configuration, a cutting edge is rotated to project outwardly from the outer surface of the mechanical cutting tool assembly such that a blade knife surface is directed outwardly and upwardly and is capable of contacting and slicing through the sidewall of the conduit when moving to the open configuration and subsequently slices through the sidewall of the conduit when the mechanical cutting tool assembly is moved vertically within the wellbore and therefore moves relative to the conduit.

16. An apparatus according to any of claims 10 to 15, wherein the cutting and expansion assembly further comprises:- a housing having an inner bore and an outer surface; and one or more expansion member(s) actuable between:- a run in hole configuration in which the one or more expansion member(s) is substantially relaxed such that the one or more expansion member(s) is spaced apart from the inner throughbore of the production tubing string; and a compressed configuration in which the one or more expansion member(s) is compressed to store compression energy within the expansion tool; and an expanded configuration in which the one or more expansion member(s) is expanded by the compression energy such that it is capable of contacting the inner surface of the section of production tubing and is capable of increasing the inner diameter of the said section of production tubing.

17. An apparatus according to claim 16, wherein the cutting and expansion tool further comprises at least one biasing means capable of:- storing said compression energy in the compressed configuration; and of releasing said compression energy to expand the one or more expansion member(s) in the expanded configuration.

18. An apparatus according to either of claims 16 or 17, wherein the cutting and expansion tool further comprises a compression device moveable with respect to the housing of the expansion tool in order to actuate the one or more expansion member(s) from the run in hole configuration to the compressed configuration.

19. An apparatus according to any of claims 10 to 18, wherein the cutting and expansion tool assembly is adapted to be run into a production tubing string and is capable of cutting and expanding a section of the production tubing, the cutting and expansion tool assembly comprising:- an upper anchor; a production tubing string cutting tool capable of forming a horizontally arranged cut through, and around the circumference of, the sidewall of the production tubing string at a first location at one end of the region of production tubing string to be removed; a telescopic member located in between the upper anchor and the production tubing cutting tool; and the cutting and expansion tool, wherein the upper anchor is capable of being actuated to anchor against the inner throughbore of the production tubing string; and the telescopic member is capable of being actuated to stroke out to increase and stroke in to decrease the distance between the upper anchor and the production tubing cutting tool such that the telescopic member is capable of being actuated to move the production tubing cutting tool.

20. An apparatus according to claim 19, wherein the cutting and expansion tool assembly further comprises a spacer member having a predetermined length and which is located in between the production tubing cutting tool and the cutting and expansion tool and which serves to separate those two tools by the length of the spacer member.

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