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This Application is the U.S. National Phase Application of PCT International Application No PCT/GB2003/003542 filed Aug. 14, 2003. 
   This invention relates to apparatus and a method for treating wells, especially but not exclusively for abandoning hydrocarbon-bearing wells. 
   DESCRIPTION OF THE RELATED ART 
   When wells have reached the end of their useful life, they need to be abandoned. The top of the casing strings must be cut off near the wellhead, whilst ensuring that no further hydrocarbons can leak through the casing strings and into the surrounding area. The bottom of the annulus between the two innermost casings is in communication with the formation. Therefore, if this annulus is not completely sealed, hydrocarbons from the formation could leak out. Usually, wells are abandoned using explosives to sever the casings. These are harmful for fish and the environment. Furthermore, underwater explosions are difficult to control and there is a risk of damaging the well plug, causing it to leak. 
   BRIEF SUMMARY OF THE INVENTION 
   According to the present invention there is provided well treatment apparatus comprising a cutting tool; a sealing device to seal a portion of a wellbore; and an anchor means to anchor the apparatus with respect to the wellbore. 
   Preferably, the sealing device comprises at least one and preferably two annular cup devices typically orientated in the same direction to provide a double seal between the portion of the well beneath the sealing device and the surface of the well. 
   Optionally, the sealing device comprises two annular cup devices orientated in opposite directions (e.g. with cups facing one another) to seal the portion of the apparatus in between the two oppositely-orientated devices from the rest of the bore. 
   Preferably, a first fluid circulation device is positioned between the two oppositely orientated cup devices. 
   Typically the cup devices can be cup-type seal assemblies, typically with axially extending conduits for e.g. control lines and fluid lines. A preferred cup device can be constructed from a packer (e.g. such as a gas line packer available from Double-E, Inc), modified so that its rubber part allows the packer to perform a sealing function, and including bulkhead connections providing axial passages through the packer. 
   Preferably, the apparatus adapted to attach to a drillstring and the sealing device is typically adapted to, in use, seal the annulus between the drillstring and the innermost casing of the wellbore. 
   Typically, the cup device has a cup-shaped body (typically at least a portion of this is made from a deformable material, such as high density rubber). Preferably, a part of the cup device is adapted to deform outwards to seal the annulus upon the application of pressure from inside the cup-shaped body. In use, fluid flowing into the cup-shaped body typically deforms the cup-shaped body so that the external face of the cup presses against the inner face of the casing, preventing or restricting fluid from flowing past the cup device. 
   Typically, a further fluid-circulating device is located between the sealing device and the cutting tool. Typically, fluid can be diverted between the circulating devices by dropping a ball/dart into the body of the apparatus. 
   Optionally, at least one further seal is located beneath the cutting tool, to seal the portion of the bore around the cutting tool from that below the cutting tool. Preferably, the at least one further seal is a cup-type seal assembly. 
   Preferably, the cutting tool comprises a jet cut nozzle that is able to cut through casings that line the bore. Preferably, the nozzle is movable e.g. rotatable in two perpendicular planes (e.g. horizontal and vertical) so that the nozzle can cut circular apertures in the casing. Preferably the nozzle/cutting tool is also rotatable through 360° to enable the cutting tool to cut around the entire circumference of the casing. 
   Optionally, the anchor means is located on the body of the cutting tool. Alternatively, the anchor means could be provided on a further sub separate from the cutting tool. 
   Preferably, at least one part of the anchor means is laterally extendable. The laterally extendable part of the anchor means typically has a foot for engaging a wall of a casing. 
   Preferably, the foot has a high-friction casing-contacting surface. Typically, the casing-contacting surface extends around the entire circumference of the anchor means. 
   A typical anchor means can be provided by modifying a packer device having an expandable anchor portion; the modification typically includes the removal of the interior packing material to leave a hollow bore through the packer. Such packer devices typically have an exterior anchor portion, which is expanded on moving a first part of the anchor device relative to a second part. 
   Optionally, the cutting tool has at least two (e.g. three or more) circumferentially spaced feet, to engage the interior of the casing at circumferentially spaced locations. The or each foot can be mounted on a moveable arm that can be driven by a ram or alternatively at least one of the feet can be static e.g. provided on the body of the cutting tool, or on an extension of the body. 
   According to a second aspect of the invention, there is provided a method of treating a well, including the steps of:
         inserting well treatment apparatus into a cased wellbore, the apparatus including a cutting tool, a sealing device and an anchor means;   perforating the innermost casing in two vertically spaced positions; and   injecting cement into a portion of the annulus between the two innermost casing strings to seal the annulus;   whereby the method includes the step of using the anchor means to anchor the apparatus to the cased wellbore.       

   Typically, the method includes the step of pressure testing the innermost casing before the first perforation is made by injecting a fluid into the wellbore below the sealing means. 
   Typically, the method includes the step of pressure testing the annulus before the second perforation is made by injecting a fluid into the wellbore below the sealing means and measuring the equilibrium rate of pumping as the fluid flows through the first perforation into the annulus. 
   Optionally, the method includes the step of pressure testing the annulus after the second perforation has been made by injecting a fluid into the annulus to check that there are no blockages in the part of that annulus lying between the vertically spaced perforations. 
   Typically, the sealing device includes two oppositely orientated cup devices, and the cement is injected into the annulus from an aperture in the apparatus located between these two cup devices. 
   Optionally, the method includes the step of pressure testing the sealed annulus by positioning the apparatus so that the sealing device lies between the two vertically spaced perforations and by injecting fluid into the wellbore below the sealing device. 
   Preferably, the method includes the step of using the cutting tool to sever the casings above the perforations after the annulus has been sealed, and typically tested for seal integrity. 
   Typically, the method including the step of undertaking at least one pressure test by injecting fluids, whereby during the pressure test, the apparatus is anchored to the casing by the anchor means to counter the upwards force on the apparatus by the injected fluids. 
   Typically, the well treatment apparatus is mounted on a drillstring and is manoeuvred in the wellbore by raising and lowering the drillstring. 
   Typically the fluid used in the pressure tests is water, but in some circumstances cement or other fluids can be used. 

   
     BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
     An embodiment of the invention will now be described by way of example only and with reference to the following drawings, in which: 
       FIG. 1  shows a partial cross-section of an abandonment string inserted into a wellbore to be abandoned; 
       FIG. 2  shows a partial cross-section of the abandonment string piercing the 9⅝″ casing; 
       FIG. 3  shows a partial cross-section of the abandonment string making a second, higher cut in the 9⅝″ casing; 
       FIG. 4  shows a partial cross-section of the abandonment string injecting cement into the annulus between the cuts; 
       FIG. 5  shows a partial cross-section of the abandonment string performing a final pressure test on the cemented annulus; 
       FIG. 6  shows a partial cross-section of the abandonment string cutting through all the casing strings at the wellhead; 
       FIG. 7  shows a schematic cross-section of the abandonment string pressure testing the 9⅝″ casing string; 
       FIG. 8  shows a schematic cross-section of the abandonment string making a cut in the 9⅝″ casing and pressure testing the annulus between the 9⅝″ casing and the 13⅜″ casing; 
       FIG. 9  shows a schematic cross-section of the abandonment string making a second cut in the 9⅝″ casing; 
       FIG. 10  shows a schematic cross-section of an integrity check of the cement in the annulus between the two cuts; 
       FIG. 11  shows a schematic cross-section of cement being injected into the annulus between the two cuts; 
       FIG. 12  shows a schematic cross-section of the cement in the annulus between the cuts being pressure tested; 
       FIG. 13  shows a schematic cross-section of the casings being cut near the wellhead; 
       FIG. 14  shows a cross section of three cup-type seal assemblies mounted on two circulating subs; 
       FIG. 15  shows a side view of a cutting tool; 
       FIG. 16  shows a side view of a portion of a cutting tool; 
       FIG. 17  shows a schematic diagram of an abandonment string; 
       FIG. 18  shows a perspective view of the abandonment string of  FIG. 17 ; 
       FIG. 19  shows a perspective view of a cup-type assembly; 
       FIG. 20  shows an end view of a body member of the cup-type assembly of  FIG. 19 ; 
       FIG. 21  shows a cross-section along the line A-A of  FIG. 20 ; 
       FIG. 22  shows an enlarged view of circle B of  FIG. 21 ; 
       FIG. 23  shows an end view of a cup-type seal of  FIG. 19 ; 
       FIG. 24  shows a cross-section along the line A-A of  FIG. 23 ; 
       FIG. 25  shows an end view of a shaft of the cup-type seal assembly of  FIG. 19 ; 
       FIG. 26  shows a cross-section along the line A-A of  FIG. 25 ; 
       FIG. 27  shows an enlarged view of region B of  FIG. 26 ; 
       FIG. 28  shows a side view with interior detail of a flange of the shaft of  FIG. 25  and 
       FIG. 29  shows a side view of the anchor of  FIGS. 17 and 18 . 
   

   DETAILED DESCRIPTION OF THE INVENTION 
   As shown in  FIG. 1 , an abandonment string  10  typically comprises a cutting tool  12 , a first circulating sub  14 , two oppositely orientated cup-type seal assemblies  16   18 , a second circulating sub  20 , a third cup-type seal assembly  22  and drill pipe  24 . 
   An enlarged view of cup-type seal assemblies  16 ,  18 ,  22  and circulating subs  14 ,  20  is shown in  FIG. 14 . Cup-type seal assemblies  16  and  22  provide two permanent barriers between the hydrocarbon bearing formation and the surface. 
   Optionally, a second cup-type seal assembly and sub arrangement may be provided beneath the cutting tool  12 . This could be useful if the plug  44  in the innermost casing has not formed a perfect seal. As shown in  FIG. 1 , the arrangement could comprise a sub  26 , fourth and fifth cup-type seal assemblies  28 , 30  arranged back-to-back, a further sub  32  and a sixth cup-type seal assembly  34 . This cup-type seal assembly and sub arrangement is inverted as compared with the arrangement above the cutting tool  12 , except that the subs  26  and  32  can be ordinary subs instead of circulating subs. It is not necessary to have this entire arrangement; cup-type seal assembly  28  would be sufficient, or cup-type seal assemblies  28  and  34 , if a double seal is required. 
   The cutting tool  12  is best shown in  FIGS. 15 and 16 . It has a rotatable jet cut nozzle  70 , which can cut through casing  36 . Cutting nozzle  70  is rotatable in both horizontal and vertical planes to allow the cutting of communication ports (i.e. cutting nozzle can cut in two dimensions). Cutting tool  12  has a pair of anchoring devices  74  that are axially spaced along the body of the tool, to anchor the tool  12  in the casing  36 . Each anchoring device  74  has three feet  78  that are circumferentially spaced around the body of the tool  12  and each foot is attached to the body of the tool  12  by a pair of link arms  72  that are each pivotally coupled at one end to an eye on the foot and at the other end to a respective eye on the body. One of the eyes on the body is mounted on a central plate that is driven axially by a hydraulic ram to push the eyes on the body together thereby extending the feet by means of the pivotal connections so that the feet move laterally to contact the casing  36 .  FIG. 16  shows one embodiment of a part of cutting tool  12 , which has a foot  78 , mounted on a pair of link arms  72 . The foot  78  typically has an abrasive outer surface with e.g. serrations so that there is high friction between the foot  78  and casing  36  when the two are in contact.  FIG. 16  also depicts an optional second foot  80 , which is mounted on an extension  82  of the body of the cutting tool  12 . The cutting tool should have at least one extendable foot  78 , and optionally at least one other foot  78  or  80 , or other high friction casing contacting surface. Typically there are two or three feet  78  each circumferentially mounted on pairs of linking arms  72  which are circumferentially spaced around the tool  12 . As shown in  FIG. 15 , more than one plate  74  may be provided. 
   The drill pipe  24  extends to the surface. Umbilicals also extend from the surface to the cutting tool  10 . 
   The abandonment string  10  is shown inside a wellbore, which has several layers of casing: 9⅝″, 13⅜″, 20″ and 30″, which are respectively designated by numbers  36 ,  38 ,  40  and  42 . 
     FIGS. 17 and 18  show a second embodiment of abandonment string  100  and like parts are designated by like numbers. Abandonment string  100  differs from abandonment string  10  in that cup-type seal assemblies  16  and  18  are shown separated by subs, whereas in  FIG. 10 , these are shown back to back. 
   Like the  FIG. 1  embodiment, abandonment string  100  is run on drillpipe  24 . Starting from the top of the string, the first component is an optional safety joint  102 . This provides a means of disconnecting drillpipe  24  from abandonment string  100  should the need arise. 
   A flex pipe  104  runs along the side of drillstring  24  and the rest of abandonment string  100 . Flex pipe  104  typically comprises a ¾ inch 15K fluid power hose to supply fluid (slurry) to cutting tool  12 . Also running along the side of drillstring  24  parallel to flex pipe  104  are electrical and hydraulic umbilical lines (not shown) to power and control the cutting tool  12 . 
   The next component in the string is cup-type seal assembly  22  and associated flex pipe assembly  200 . Cup-type seal assembly  22  is shown in more detail in  FIGS. 19 to 28 . Cup-type seal assemblies  16 ,  18  further down the string are typically exactly the same, but for ease of reference numbering, the cup-type seal assembly is denoted simply as  22 . 
   Cup-type seal assembly  22  includes a body member  106 , a seal  108 , a shaft assembly  110  and an o-ring seal  112 . Body member  106  is substantially cylindrical. It has a shaft-engaging portion  120  and a seal-engaging portion  122 . Shaft-engaging portion  120  has a smooth outer surface of constant diameter. Shaft-engaging portion  120  is divided into two portions with different inner diameters; an end portion  150  of diameter 188 mm and a mid portion  152  of diameter 175 mm; end portion  150  and mid portion  152  are divided by a step  125 , which lies at 53 mm from the end of body member  106 . It should be noted that throughout this specification all dimensions are exemplary rather than limiting 
   The outer end of the end portion  150  is provided with four holes  123  equally spaced around the circumference for the insertion of grub screws. Adjacent to holes  123 , end portion  150  has 7.375-6 ACME-2G threads  127  which terminate a short distance before step  125 . 
   Mid portion  152  is provided with a groove  124  to accommodate o-ring seal  112 . Mid portion  152  then continues uniformly up to a distance of 92 mm from the end of the shaft-engaging portion  120 , where there is a further step  128  which marks the boundary between the shaft-engaging portion  120  and the seal-engaging portion  122 . 
   The seal-engaging portion  122  comprises an extension of the shaft-engaging portion and is provided with undulations on both of its inner and outer surfaces. The seal-engaging portion  122  is thinner than the shaft-engaging portion  120 , having a larger inner diameter and the same outer diameter. Eight radial apertures  126  are provided in the seal-engaging portion  122 , equally spaced around the circumference; more or fewer apertures could be provided here, or even none at all. 
   Seal  108  is best shown in  FIGS. 24 and 25 . Seal  108  is also basically cylindrical with a body-engaging portion  132  and a radially-extending end  130 . Body-engaging portion  132  is shaped to co-operate with the seal-engaging portion  122  of body member  106 . Body-engaging end  132  of seal  108  is provided with a cylindrical recess  134  corresponding to the seal-engaging end  122  of body member  106 , i.e. the cylindrical recess  134  has undulating inner and outer surfaces adapted to co-operate with the undulations on seal-engaging end  122 . Seal  108  is coupled to body member  106  by the seal-engaging end  122  of body member  106  engaging the co-operating cylindrical recess  134  of seal  108 , with end  133  of seal  108  abutting against step  128  of body member  106 ; the undulations act to resist separation. 
   Radially-extending end  130  is an extension of a body-engaging end  132  and it tapers outwards from body-engaging end  132 , with both the inner and outer diameters increasing. The inner diameter increases at a greater rate than the outer diameter, so that the radially-extending end  130  gets thinner as it tapers outwards. 
   Seal  108  is preferable made of a rubber composition, preferably 70-80 durometer Nitrile which is suitable for hydrocarbon use; however other materials could also be used. 
   Shaft assembly  110 , as best shown in  FIGS. 25 to 28  includes a hollow shaft  140  and flange  142  extending outwardly of shaft  140 . The shaft  140  has a box and a pin connection on respective opposite ends. Flange  142  is shaped to engage and co-operate with the shaft-engaging end  120  of body member  106 . Flange  142  is provided with 7.375.6 ACME-2G screw threads  143  on its outer surface for connection with screw threads  127  on body member  106 . Flange  142  has a radial projection  144  on the end of flange  142  closest to the pin connection, and a stepped recess  147  on the opposite end of flange  142 . Between radial projection  144  and threads  143  is an unthreaded gap  145 . 
   Flange  142  is provided with eight passages  146  of 11.8 mm diameter extending through flange  142  parallel to the axis of shaft assembly  110 . Passages  146  are threaded at their upper and lower ends for the first 20 mm for engagement with respective bulkhead connections (not shown). One bulkhead connection is supplied for each end of each passage  146 . Passages  146  are to enable the electrical and hydraulic umbilical lines to continue past cup-type seal assembly  22 ; each umbilical line terminates at the first bulkhead connection, the first bulkhead connection provides a continuation of the umbilical line through respective passage  146  to the second bulkhead connection on the opposite side of flange  142 , which is in turn connected to a further umbilical line on the other side of flange  142 . The bulkhead connectors can each be sealed closed, so that if any passage  146  is not being used, the respective bulkhead connectors are sealed so that no fluids can get through that passage  146 . 
   Two further passages  141 ,  148  of larger (25.4 mm) diameter are provided in flange  142 . Passages  141 ,  148  are threaded for the first ⅝ inches at their upper and lower ends. 
   Passage  141  allows the flex pipe  104  to continue through flange  142 . Passage  141  also has a bulkhead connection, in the form of flex pipe assembly  200 . Flex pipe assembly  200  is a means of connecting a portion of flex pipe  104  on one side of cup-type seal assembly  22  to a further portion of flex pipe  104  on the other side. Flex pipe assembly  200  typically includes a further portion of flex pipe  104  which passes through passage  141  in flange  142 ; flex pipe assembly  200  typically includes one or more seals (not shown) to seal between the exterior of flex pipe  104  and the interior of passage  141 . 
   Two blind passages  149  are also provided in the flange, equally spaced on either side of passage  141 . Blind passages  149  are typically used to receive bolts to secure flex pipe assembly  200  to shaft assembly  110 . 
   Remaining passage  141  also has a bulkhead connection on each side of flange  142 . Passage  141  can be used to accommodate a return fluid line or an extra flex pipe for slurry (not shown) or alternatively, if not used, it could be sealed closed at its bulkhead connections. 
   Passages  141 ,  146 ,  148 ,  149  are circumferentially distributed on flange  142 . 
   Referring back to  FIG. 18 , cup-type seal assembly  22  is orientated in the string  100  with the seal end (and the box connection of shaft assembly  110 ) pointing downwards. The pin of shaft assembly  110  is attached to drillstring  24  as shown in  FIG. 17 . 
   When fluid flows into the seal end of cup-type seal assembly  22  (i.e. fluid flowing upwards on the outside of string  100  in this embodiment) the radially-extending end  130  of seal  108  is pushed outwards to engage the casing wall. The greater the pressure from the fluid, the more the radially-extending end  130  is pushed against the casing, and the better the seal. Therefore, fluid flowing upwards in the annulus between the string  100  and the innermost casing string cannot get past seal  22 . 
   The box of shaft assembly  110  is attached to a pin-pin sub  202 , followed by a crossover sub  204 , two pin-box ported subs  20   a ,  20   b , a further cross-over sub  210  and a pin-box sub  212 . (Note that in this embodiment, there are two pin-box ported subs  20 , whereas in the  FIG. 1  embodiment only one was shown). 
   At this point in the string is cup-type seal assembly  18 ; this is exactly the same as cup-type seal assembly  22  and the above description of cup-type seal assembly  22  is equally applicable here. However, the orientation of cup-type seal assembly  18  is the reverse of the former seal assembly  22 ; i.e. where cup-type seal assembly  22  has its seal  108  pointing downwards, cup-type seal assembly  18  has its seal pointing upwards. Thus, in this case, it is the box connection of shaft assembly  110  that is attached to pin-box sub  212 . Because of the opposite orientation, fluid flowing downwards in the annulus between string  100  and the innermost casing, is stopped by cup-type seal assembly  18 . 
   Also as described above, a further flex pipe assembly  200  allows flex pipe  104  to pass through passage  141  in flange  142  whilst forming a seal around the outside of the passage. 
   The pin connection of shaft assembly  110  is attached to pin-box sub  214  and the drillstring continues with box-box sub  216  and further pin-box sub  218 . 
   A further cup-type seal assembly  16  and respective flex pipe assembly  200  is attached to pin-box sub  218 . Cup-type seal assembly  16  is exactly the same as cup-type seal assemblies  18 ,  22  described above, and has the same orientation in the string as cup-type seal assembly  22  (i.e. opposite to assembly  18 ). Thus, cup-type seal assemblies  16 ,  22  both act to prevent fluid flowing upwards from the well to the surface. 
   Connected to shaft assembly  110  of cup-type seal assembly  16  is a pin-pin sub  220  and pin-box ported sub  14 . Pin-box ported sub  14  has a blind ending, and three transverse passages (although only one is necessary) leading from an inner bore to the outside of abandonment string  100 , providing fluid communication with the outside of the string  100 . Ported sub  14  allows for pressure testing beneath cup-type seal assembly  16 , circulating through perforations as required and pressure monitoring during perforations. It also allows a fluid return path (via the drillpipe  24 ) for the cutting tool power fluid whilst cutting operations are in progress. Furthermore, bullheading the perforated casing annuli can be carried out via sub  14 . Shield bracket  226  is provided on sub  14 . The next element is apertured sub  224 , which has at least one side aperture to allow the entry of flex pipe  104  into a hollow bore of apertured sub  224 . Apertured sub  224  may also have a further aperture for entry of a further fluid return pipe (not shown) into the hollow bore. 
   Attached to apertured sub  224  is anchor sub  228 ; this is best shown in  FIG. 29 . Anchor sub  228  replaces the anchoring device  74  shown in  FIGS. 15 and 16  (used in abandonment string  10 ). Anchor sub  228  is a modification of a casing packer. The modification typically includes the removal of the inner packing material, leaving a central hollow bore for the passage of flex pipe  104  and the umbilicals. Anchor sub  228  has a first portion  232  and second portion  234  which are slideable relative to each other; the second portion  234  having a tapered portion  238 , which in turn has a reduced-diameter extension  236 . The first portion  232  has grippers  240  on the end closest to the second portion. To activate anchor  228 , the second portion  234  is moved upwards relative to first portion  232 , which causes grippers  240  to be pushed radially outwards as they travel along tapered portion  238 . Grippers  240  engage the inner surface of the cased wellbore to anchor abandonment string  100  to the casing. 
   Attached to anchor sub  228  is cutting tool  12 , which can be the same anchoring tool as shown in  FIG. 15 . Cutting tool  12  in this embodiment does not need to have feet  78  as abandonment string  100  already has an anchor  228 , although these may be still be provided if desired. 
   Cutting tool  12  has a hollow internal passage to allow passage of flex pipe  104  and the umbilical lines (not shown). Cutting tool  12  has a cutting nozzle  70  (see  FIG. 15 ). The cutting tool  230  is controlled and powered by the umbilicals; fluid (typically slurry) is supplied to cutting nozzle  70  by flex hose  104 . The remaining features of cutting tool  12  have already been described above with reference to  FIG. 15  and the abandonment string  10  embodiment. 
   In use, when the corrosion cap/temporary abandonment cap has been removed from the well, a drill string with a rock bit is run into the wellbore, to check that it is free of obstructions. The drill string is typically made up of 3½″ or 5″ drill pipe. 
   The abandonment string  10 ,  100  is made up and run into the hole to a depth of typically 100-400 metres (in some cases up to several thousand metres) beneath the wellhead. The top drive is then made up or the string is connected to a circulation device. 
   With abandonment string  10 , the cutting tool  12  in the string is then anchored to e.g. the 9⅝″ optionally below the wellhead by extending the rams  72  so that the feet  78  contact the casing  36 . The abandonment string  10  is thus held fixed relative to the casing  36  by friction between the feet  78  and the casing  36 . If abandonment string  100  is used, anchor  228  is engaged as described above by moving second portion  234  towards first portion  232  until the grippers  240  grip the casing sufficiently. 
   As shown in  FIG. 7 , the casing  36  is pressure tested, to check its integrity. This is done by pumping fluid down through the abandonment string  10 ,  100  and out through an aperture in circulating sub  14 . The fluid is constrained within the area bounded by an existing plug  44  (fitted when the wellbore was temporarily abandoned), the cup-type seal assemblies  16 ,  22  and the casing  36 . This tests the pressure integrity of the casing and of the plug  44  and identifies whether there are any fissures through which significant amounts of hydrocarbons can leak from the formation. 
   It may be advantageous to only engage the anchor after the pressure has already begun to build up. The anchor is useful to prevent the pressure build up underneath cup-type seal assembly  16  from forcing abandonment string  100  out of the well. 
   Assuming that the casing  36  and the plug  44  do not have any substantial leaks, the cutting tool  12  then cuts two (typically circular) holes  46 ,  48  in opposite sides of the casing  36 , as shown in  FIGS. 2  and  8 . It is not necessary to cut two holes; one would suffice, nor is it necessary for the holes to be opposite each other. 
   A second pressure test is then performed by pumping fluid  50  (e.g. water) through the abandonment string and out through the aperture in circulating sub  14 , in the same manner as the first pressure test. The fluid  50  passes out through the holes  46  and  48  and into the annulus  52  between the casing  36  and the casing  38 . Some of the fluid  50  may escape down the annulus  52  and into the formation. The rate of pumping is varied so that equilibrium is reached between the amount of fluid  50  entering and leaving the annulus  52 . The equilibrium rate of pumping and pressure are recorded. A typical equilibrium rate might be 2-3 barrels per minute at a pressure of 3,000 pounds per square inch. This test is done to establish a bench mark for the next pressure test. It also establishes the integrity of the casing  38 ; if there is very low pressure in the annulus  52  after pumping fluid  50  into it, that could indicate leaks in the casing  38  or the cement job. If there is a very high back pressure, which could be caused by hydrocarbons in the annulus/formation, the excess fluid will have to be removed via the string before proceeding. 
   The anchoring means are then deactivated to release the cutting tool  12  from the casing  36  and the abandonment string  10 ,  100  is then raised so that the cutting tool  12  is approximately 400-500 feet above the first cuts  46 , 48  as shown for example in  FIGS. 3 and 9 . The anchoring means are then reactivated so that the cutting tool  12  is re-anchored to the casing  36  (i.e. by extending the link arm  72  to push the feet  78 ,  80  against the casing  36  in the  FIG. 1  embodiment, or by moving the first and second portions  232 ,  234  away from each other in the  FIG. 17  embodiment). A pair of second cuts  54 ,  56  are made with the cutting tool  12  in opposite sides of the casing  36  as before. Again, it is not necessary to cut twice; one cut would suffice. In some cases a further pressure test as described previously can be carried out through the newly made cuts  54 ,  56 , but this is not necessary. 
   The anchoring device is then deactivated to release the cutting tool  12  from the casing and the abandonment string  10  is lowered down the borehole so that the cup-type seal assemblies  16  and  22  are between the two sets of cuts  46 ,  48  and  54 ,  56 , as shown in  FIG. 10 . Fluid is then pumped from the lower sub through cuts  46 ,  48  and into the annulus  52  between the two sets of cuts  46 ,  48  and  54 ,  56 . If the fluid pathway is open in the annulus  52 , fluid pumped through the string  10  should flow through cuts  54 ,  56  without significant measurable pressure build up at surface. 
   The abandonment string  10  is then detached from the casing, lowered and re-anchored so that the first cuts  46 ,  48  are positioned between cup-type seal assemblies  18  and  22 , as shown in  FIG. 11 . A ball or dart is dropped through the abandonment string  10  so that it diverts fluid from the circulating sub  14 . Cement is then pumped down the abandonment string  10 . The cement  58  passes out of the hole  20  in circulating sub and into the annulus  52 . 
   When no more cement can be pumped in at a reasonable rate and pressure (with reference to the readings taken earlier) this indicates that the annulus between the cuts is well sealed. Alternatively a cement slug of a known volume can be injected into the string and is pumped through the tool  12 . The volume of the slug is calculated to create a plug extending the length of the annulus between the cuts  46 ,  48  and the cuts  56 , 58 . Typically the distance between the first and second cuts is at least 100 feet, and typically an excess of cement (e.g. 2-300%) is used in order to ensure that the annular cement plug is sufficiently long. 
   The anchoring devices are then deactivated and the string  10  is pulled up out of the borehole before the cement sets. Excess cement that has emerged from the upper cuts  56 ,  58  is wiped out of the bore by the seals on the tool  12 . At this time, the tool can be redressed to remove the ball/dart from the circulating sub  14  so that fluid can circulate through the sub  14  once more. 
   When the new cement is set, the string  10  is run into the borehole again so that the cup-type seal assemblies  16 ,  22  are in between cuts  46 ,  48  and cuts  54 ,  56 , as shown in  FIGS. 5 and 12 . The annular plug of cement in the section  60  of annulus  52  between the cuts  46 ,  48  and cuts  54 ,  56  should now be solid. To test this, fluid (e.g. water) is then pumped down the string  12  and through the hole in the circulating sub  14 . If no significant injection of fluid into the annulus  52  is possible, then this proves that the cement job has been successful and that the section  60  of annulus  52  is firmly sealed. 
   If this is the case, the tool  10  is unanchored, raised and re-anchored so that the cutter of the cutting tool  12  is near the wellhead. The cutting tool  12  is then used to cut through all the casings  36 ,  38 ,  40 ,  42  by continuous cutting while the head rotates around 360°. 
   In the case of the string  100 , the procedure is the same but the port  20   a  between the cups  22 , 18  can optionally be used for cement injection, whereas the other port  20   b  can be used for pressure testing between the upper  22  and lower  18  seals prior to any perforations being made. Thus testing of the upper and the lower seals  22 ,  16  can optionally be done without moving the string. 
   Modifications and improvements may be incorporated without departing from the scope of the invention. For example, after the cement has been injected into the annulus, instead of withdrawing the string  10 , 100  back to surface, the string  10 , 100  can be pulled up just above the upper perforations  54 , 56 , to wait on cement (if a cement slug has been used) or can be pulled up until the ports  20  are above the wellhead, where the cement can be purged from the drillstring, the port  20   a , and the area between the seals  22 , 18 . When the cement has been purged (if necessary) then the string  10 , 100  can be run back into the hole to test the integrity of the annular cement seal at  60 , by pumping seawater through either of ports  20   a  and  20   b . This therefore allows the whole operation to be completed in a single run. In a further modification of the method, further radially outward annuli can be sealed in exactly the same way, optionally on the same run in the hole, by cutting through the two innermost layers of casing and into the second annulus behind that already sealed. Typically the plug in the second annulus overlaps the first plug, in accordance with normal procedures, and this can be achieved by making the first cut for the second plug between the first and second cuts of the first, and then raising the string  10 , 100  to a level above the second (upper) cuts of the first plug, before making the second (upper) cuts for the second plug. Clearly the outer plug could be set at a lower level than the first plug. 
   The high pressure rating of the tool allows control of hydrocarbons behind the perforated casings, and also can be used to inject behind numerous radially outward casings outside the innermost casing, or to break down the formation at these points. This high-pressure capability is useful if bullheading is required. Cutting through radially outward casing strings can be detected by observing pressure drops in the slurry hose. 
   When moving the string  10 , 100  through the hole the plunger effect can be minimised by allowing free passage of fluid through the string  10 , 100 . Also, swabbing can be minimised when pulling out by pumping fluid down the string  10 , 100 . 
   Embodiments of the present invention have the advantage that no explosives are used, which makes it more environmentally friendly. This also eliminates the risk of shattering the well plugs using explosives. Also, by following the method described above, the casing can be perforated and pressure tested, cement injected into the annulus between casings to seal the annulus and the casings severed all on a single run operation. Furthermore, the cutting tool can also be used to cut the concrete pancake at the top of the wellhead, breaking it up and hence reducing the amount of weight to be lifted after the casings are severed. The equipment is usually run on a drillstring, and can be run on coil tubing, so the abandonment string can be run from a derrick vessel, or a floating/jack-up rig, without requiring more expensive and permanent platforms, or even diving support vessels.

Summary:
A well abandonment apparatus is described. The apparatus can be run on drillstring and does not require the use of explosives to sever the casing. The apparatus includes both a cutting device to perforate and sever the casing and a sealing device to prevent well fluids from reaching the surface while the well abandonment operation is proceeding.