LIVE WELL INJECTION

Abstract

An apparatus and method for injecting and/or withdrawing items into/from a pressurized downhole, pipeline or the like when carried on or by a tubular length are disclosed. The apparatus can include two or more pressure sealing units for sealing against the length as it is injected. The sealing units can be joined by a pressure lock section, and the sealing units can be movable between a sealed position in which they are sealing against the tubular length and a retracted position. The apparatus may also include means for controlling pressure in the pressure lock section, in which the sealing units can be selectively and sequentially moved from the sealed position to the retracted position to allow introduction of an item therethrough, and in which the pressure lock section is selectively pressurizable and depressurizable to allow the item to move from low to high or high to low pressure during injection or removal.

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims priority to U.S. Provisional Application No. 61/980,992, filed on Apr. 17, 2014 which is incorporated fully herein by reference

FIELD

The present disclosure relates generally to the injection of tubes, pipes, cables and the like into pressurized downholes, wells, pipelines and the like.

BACKGROUND

CT (Coiled Tubing), Slickline, Wireline and drill pipe have been used by the oil and gas industry for many years to insert various tools and sensors, including those used for well intervention, into open boreholes, cased boreholes, production tubing and other types of pipe or bore hole.

A key advantage offered by CT, Slickline and Wireline over drill pipe, which requires the joining of multiple rigid straight tubes, is that because it is generally of a single continuous length (although multiple coils of coiled tubing are often joined together), it allows a faster rate of deployment and recovery of a tool string. Another key feature of CT, Slickline and Wireline is that they generally have a continuous, relatively smooth and constant diameter, which can be pushed or pulled through a pressure sealing device known in the art as a stripper/stuffing box. Being able to deploy a tool string into a pressurized (live) well offers significant advantage, in that it reduces well/pipeline down time, including time required to first ‘kill’ or depressurize a well/pipeline, which can potentially lead to irreversible well damage.

FIG. 1A and FIG. 1B show silhouettes of typical coiled tubing stacks attached to production Christmas trees 15. The production Christmas tree 15 is used to control production flow from the production tubing, and the valves that make it up can close off well pressure, which allows attachment of CT, Slickline or Wireline injecting equipment. Directly attached to the top of the production Christmas tree 15 is a quad BOP 14 (Blow Out Preventer—a safety device used to seal the well in the event of a failure), which can be used to seal around the inserted CT/Slickline/Wireline to contain well pressure, hold the weight of the CT/Slickline or Wireline string, shear the CT/Slickline/Wireline, and seal the full bore diameter following a CT/Slickline/Wireline shear. Each BOP function has a separate set of rams, although more modern duel BOP's use only two sets to perform all four functions. Above the BOP is usually a Lubricator 12, although a radial type stripper 13 can be installed between them. The purpose of the Lubricator 12 is to give enough height to house the tool string before insertion into the well, as the tool string must fit between the closed valve on the Christmas tree 15 and the axial Stripper 11. In some cases the tool string length is short enough that it does not require a Lubricator, with BOP and other CT, Slickline or Wireline stack equipment able to accommodate it. The use of two Strippers 11 or 13 used in tandem in the stack at a well head has become a routine practice in the art, as it minimises the down time having to replace packer elements.

The two standard stripper/stuffing box types known to the art, are the axial compression stripper shown in FIG. 2, and the radial stripper shown in FIG. 3. The axial stripper/stuffing box uses a cylinder 29, which is in line with the stack, to compresses the polymeric element 21 between a lower bush 28, and an upper bush 27, with the element sealing around the coiled tubing 24. A gland nut 25 is used to retain the packer and bushes, and to react the axial forces applied by the cylinder piston 29. To prevent the packing element from being extruded, the inside diameter of either bush is close to that of the coiled tubing outer diameter, so limiting the area of packing element 21 exposed to the well pressure. Bushes 27 and 28 and packing element 21 can be changed out to suit different coiled tubing diameters, or just to replace worn packing elements. To compress the packing element 21, hydraulic pressure is applied to the lower cylinder port 22. To release the seal, hydraulic pressure is applied to the lower port 23. The packing element 21 does not open up enough to allow any item of larger diameter than the coiled tubing 24 to pass through it.

A radial type striper uses two opposing and inline cylinders 31, which are perpendicular to the stack, to directly push and compress the polymeric element 44 against the coiled tubing 24. As with the axial stripper, the radial stripper packing elements 44 are prevented from being extruded from well pressure by bushes 43. When hydraulic pressure is applied to the full bore side inlet 34, the piston 33 moves a pusher plate 32 via a directly connecting rod 36, which pushes against the energizer 45. The energizer 45 pushes the packer element against the coiled tubing, but also pushes the bushes, which are essentially two halves of a ring, against each other. Because the energizer 45 has significant elastic deflection (the energiser is preferably a soft polymeric material), the packing elements 44 continue to be compressed against the coiled tubing after the bush halves 45 have come together. Applying hydraulic pressure to the cylinder annular side inlet 35 pulls the entire packer assembly away from the coiled tubing 24, enough to open the Stripper to full bore diameter, which would enable items of larger diameter than the coiled tubing to pass through. As the packing elements are moved between being pushed against the coiled tubing and fully retracted, a bypass port 42 permits pressure equalization between the pusher plate 32 and packer element 44 face.

Traditionally the majority of wells being drilled had been nearly vertical, and the self-weight of CT, Slickline or Wireline would be sufficient to lower the tool string into the well, with the injector used to hold the string tension. With increasingly longer inclined and horizontal wells now being drilled, injectors are required to exert a compressive push force rather than to simply hold string weight. The self-weight of inclined or horizontal sections of CT/Slickline or Wireline creates such large frictional forces, that the injector push force required to overcome them eventually leads to helical buckling, which in doing so creates further frictional resistance. A point is reached whereby any increase in push force will be matched by a further increase in friction, that will simply cause additional buckling without moving the tool string any further. One way that the frictional forces can be reduced, and also provide improved lateral support to better resist helical buckling, is by attaching what is known in the art as Skates, which use either wheels or rollers against the borehole wall to reduce friction while supporting the CT/Slickline or Wireline more centrally within the well (a Centraliser with low friction coating would also give similar improvement). They are attached along the length of the CT/Slickline or Wireline as it is injected. The reduced friction means that the CT, Slickline or Wireline can reach greater distances along the well trajectory before frictional forces prevent further travel. In addition, giving radial support will delay the onset of helical buckling, further improving the distance that can be injected.

While Skates and Centralisers can offer improved injectable range, they are not applicable for use with pressurized wells/pipelines, as the equipment and arrangement of stacks used in the art, such as those shown in FIG. 1, do not permit items of larger diameter than the CT/Slickline or Wireline from being injected through the seal (Stripper), while still containing well/pipeline pressure.

Additionally, as items such as skates and centralisers cannot be stored with the CT/Slickline or Wireline on the reel, they need to be attached and removed during the operation's injection and recovery phases. The current art of attaching these items requires injecting/removal to pause, while the items are manually attached using a bolted clamp or similar.

According to a first aspect there is provided apparatus for injecting and/or withdrawing items into/from a pressurized downhole, pipeline or the like when carried on or by a tubular length, the apparatus comprising two or more pressure sealing units for sealing against the length as it is injected, the sealing units being joined by a pressure lock section, the sealing units being movable between a sealed position in which they are sealing against the tubular length and a retracted position, the apparatus further comprising means for controlling pressure in the pressure lock section, in which the sealing units can be selectively and sequentially moved from the sealed position to the retracted position to allow introduction of an item therethrough, and in which the pressure lock section is selectively pressurizable/depressurizable, whereby to allow the item to move from low to high or high to low pressure during injection or removal.

The term “tubular length” may mean, for example, CT, Slickline and Wireline, drill pipe and the like.

A further aspect provides a method of injecting or removing items into or from a pressurized downhole, pipeline or the like when carried on or by a tubular length, the method comprising the steps of: providing two or more sealing units that seal against the length as it is injected; providing a pressure lock section which joins the sealing units; moving a first, earlier sealing unit to a retracted position whilst a second, later unit is in a sealed position; moving the item through the earlier sealing unit and into the pressure lock section; closing the first sealing unit; equalizing the pressure in the pressure lock section with the pressure beyond the later sealing unit; moving the later sealing unit to a retracted position to allow the item to pass therethrough; and moving the later sealing unit to a sealed position.

The method may further comprise the steps of: depressurising the pressure lock section; and moving the upstream sealing unit to a retracted position.

A further aspect provides a method of removing items from a pressurized downhole, pipeline or the like when carried on or by a tubular length, the method comprising the steps of: providing two or more sealing units that seal against the length as it is withdrawn; providing a pressure lock section which joins the sealing units; moving a first, earlier sealing unit to a retracted position whilst a second, later unit is in a sealed position; moving the item through the earlier sealing unit and into the pressure lock section; closing the first sealing unit; equalizing the pressure in the pressure lock section with the lower pressure beyond the later sealing unit; and moving the later sealing unit to a retracted position to allow the item to pass therethrough.

The present disclosure enables the injection of large items such as tools, sensor packages, Centralisers and Skates into live wells, so that the benefits they provide to operations, such as sufficiently reducing friction to allow further reach into inclined or horizontal sections, can be taken advantage of. The ability to inject tools to greater distances in pressurized wells or pipes is of major advantage, but even more so now with the increasing length of inclined or horizontal distances being drilled in industry.

The present disclosure may, for example, be applicable to water or gas distribution pipelines, oil and gas wells, carbon dioxide sequestration plants and natural gas reservoirs. The present disclosure gives particular benefits in pressurized lines, where intervention is required without the need to depressurize.

The system may be installed as the top/first component of the pressure retaining stack or other such pressure control equipment.

The system may comprise two or more pressure sealing units of the type known in the art as Strippers or Stuffing boxes, although additional units could be used to produce multiple pressurized gated sections. The units are used to maintain a pressure seal around the CT, Slickline, or Wireline as it is injected or removed (Stripped in/out) from either a well bore or a pipeline. The sealing units are able to retract their sealing arrangements to at least, or in excesses of, the diameter of the well/pipeline being injected into (objects that are able to pass though the well or pipeline are to be capable of passing though the sealing units in their open position). The sealing units may be separated by a section of pipe whose inside diameter is at least, but preferably matching, the inside diameter of the pipe being injected into. The section between sealing units serves as a gated pressure lock, which items move into and out of before moving from high to low, or low to high pressure.

In some embodiments the apparatus consists of only two sealing units and one pressure lock section.

In one embodiment, during injection, sealing is done with the later unit while the other unit is kept fully open, with injecting/stripping operations carried out as would be done in the art. An item, such as a Centraliser or Skate, is attached to the CT, Slickline, or Wireline, which will then pass through the first seal before entering the section between them. Once within that section, the seal through which the item has passed, is closed, and section between seals pressurized to match that on the other side of the forthcoming closed seal. The seal to which the item will next pass through, now being of equal pressure either side, is opened to allow passage of the item. The CT, Slickline, or Wireline is continued to be injected, with the first seal passed through now containing the well/pipeline pressure. Once the item has moved beyond the fully open later seal, it again closes. The section between seals is then safely depressurized/vented (can also be drained if required, or even purged with an inert gas) before reopening the first seal. Injection operations through the later seal continue until attachment of another item/Centraliser/Skate.

The removal of CT, Slickline, or Wireline is done in a similar manner to that described for injection, but with the first seal now being closed for the majority of the stripping operation, and the second seal only closing when an item has entered the section between the seals.

Further aspect of the present disclosure address the problem of attachment and removal of items such as tools, sensor packages, Centralisers and Skates, which in the current state of the art require manual clamping, normally done by bolting.

A further aspect provides a chassis for detachably attaching items on a tube, pipe, cable or the like intended to be injected into a downpipe, pipeline or the like.

A further aspect provides a machine handlable chassis for detachably attaching items on a tube, pipe, cable or the like intended to be injected into a downpipe, pipeline or the like.

A further aspect provides an automatically attachable/detachable centraliser for a tube, pipe, cable or the like intended to be injected into a downpipe, pipeline or the like,

The centraliser may comprise two or more parts that can be clamped together on or around a tube, pipe, cable or the like.

The present disclosure also provides apparatus for automatically attaching and/or removing the centraliser as described herein.

The present disclosure also provides an automatically attachable/detachable skate for a tube, pipe, cable or the like intended to be injected into a downpipe, pipeline or the like,

The skate may comprise two or more parts that can be clamped together on or around a tube, pipe, cable or the like.

The chassis, skate, centraliser or the like formed in accordance with the present disclosure may use one or more of ratchets, bayonets, springs and magnets to attach on or around a tube, pipe, cable or the like,

The chassis, skate, centraliser or the like formed in accordance with the present disclosure may be, or may form part of, or allows attachment of a centraliser, a tool, a sensor, or a skate.

The chassis, skate, centraliser or the like formed in accordance with the present disclosure may be formed so as to be compatible with a machine so that they can be automatically attached and/or detached.

The present disclosure also provides an apparatus for automatically attaching and/or removing the skate as described herein.

The present disclosure also provides an automated machine for attaching and/or removing items to/from an injectable downpipe tube, pipe, cable or the like.

A further aspect of the present disclosure provides a centraliser for a tube intended to be injected into a downpipe, pipeline or the like, the centraliser comprising two or more parts that can be clamped together around a tube.

A further aspect provides apparatus for automatically attaching and/or removing the centraliser described herein.

A further aspect provides a skate for a tube intended to be injected into a downpipe, pipeline or the like, the skate comprising two or more parts that can be clamped together around a tube.

A further aspect provides apparatus for automatically attaching and/or removing the skate described herein.

A further aspect provides an automated machine for attaching and/or removing items to/from an injectable downpipe tube.

To avoid having personnel located below the injector, and above what could be a seal retaining pressure from a live well, then an automated attachment machine could be used alongside the first invention. In addition to offering safe attachment of tools, sensor packages, Centralisers and Skates above a live well/pipe line, it would also offer reduction in injection and removal times, with items attached while CT, Slickline or Wireline is continuously being injected or removed from the well/pipeline. Items such as Centralisers and Skates will be clamped on using, for example, either a bayonet or spring system rather than bolting, the mechanism of which can be quickly released, allowing the item to be removed by an automated process.

A further aspect provides a centraliser comprising a quick-connect system.

A further aspect provides a centraliser including an axial restraint means. In other words, the centraliser does not require any further axial restraint. The centraliser may comprise or includes clamp means for clamping onto or around a tube, pipe, cable or the like. The centraliser may comprise two ends and one of the two ends provides the axial restraint.

The present disclosure also provides a pipeline, downhole or the like system including apparatus as claimed and described herein.

The present disclosure also provides a pipe, tube, cable or the like intended to be injected into a downhole, well, pipeline or the like and fitted with an item as claimed and described herein. The item may, for example, be a tool or tool string, a sensor or sensor array, a centraliser or a skate.

A further aspect of the present disclosure relates to a method for determining the required Skate/Centraliser position and spacing along the CT/Slickline or Wireline.

A further aspect of the present disclosure relates to an algorithm for determining the required Skate/Centraliser position and spacing along the CT/Slickline or Wireline.

An aspect of the present disclosure provides a method for determining the required position and spacing of centralisers, skates and the like along an injectable tube, the method taking into account one or more of the following criteria:

• • predicted final position;
  • well/pipeline profile;
  • number of, position and tightness of bends, length of inclined/horizontal sections,
  • well pressure profile along the well trajectory,
  • well fluid/gas properties,
  • well/pipeline ID,
  • CT/Slickline or Wireline OD and thickness
  • detail on possible tapering wall thickness of CT,
  • well temperature profile along the well trajectory,
  • injection speed.

The position and spacing of Skates/Centralisers may be calculated based on, but not limited to, predicted final position, well/pipeline profile (number of, position and tightness of bends, length of inclined/horizontal sections), well pressure, well fluid/gas properties (density, viscosity), well/pipeline ID, CT/Slickline or Wireline OD and thickness (Including detail on possible tapering wall thickness of CT), temperature, and injection speed. The required Skate/Centraliser positions attained from calculation could be used to set the automated attachment/removal machine of the second disclosure, or used for manual Skate/Centraliser attachment.

Further embodiments are disclosed in the dependent claims attached hereto.

Different aspects and embodiments of the disclosure may be used separately or together.

Further particular aspects of the present disclosure are set out in the accompanying independent and dependent claims. Features of the dependent claims may be combined with the features of the independent claims as appropriate, and in combination other than those explicitly set out in the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention will now be more particularly described, with reference to the accompanying drawings, in which:

FIG. 1A and FIG. 1B show silhouettes of example coiled tubing stacks attached to production Christmas trees;

FIG. 2 shows an example axial compression stripper;

FIG. 3 shows an example radial stripper;

FIG. 4 is a schematic representation of an injection apparatus formed according to an exemplary aspect;

FIG. 5A to FIG. 5D show the operation of the apparatus of FIG. 4;

FIG. 6A to 6D show a centraliser formed according to a further aspect;

FIG. 7A to 7D show a skate formed according to a further aspect;

FIG. 8 shows a centraliser formed according to a further embodiment; and

FIG. 9 is a schematic representation of an automated attachment/removal machine.

DETAILED DESCRIPTION

Referring now to the drawings, FIG. 4 depicts an embodiment of the present disclosure, which is in essence a ‘pressure lock’ for items moving between low to high and high to low pressure regions. The embodiment consists of two radial type strippers 52 and 53, which are capable of opening up to equal or greater internal diameter than that of the well/pipeline the item/s are being injected into. While radial type strippers are one example, any seal that can sufficiently contain well/pipeline pressure while CT/Slickline or Wireline is being pushes/pulled through them, and open to allow items of the same diameter as the well/pipeline to pass through, could be used.

The embodiment shown is of a single body 51, however, the sealing units could be standalone assemblies, possibly existing stripper units used in the art, joined together with a section of tube using standard API connection or bolted flanges. The length of tube, or distance between sealing units 52 and 53, will be sufficient to accommodate the length of item being passed through, or of such length that with CT/Slickline or Wireline being continuously injected there is sufficient time for the first pressure seal to close, the section to pressurize, and lower seal to open before the attached item reaches lower seal 52. The length between sealing units could also be used to house the tool sting, thereby replacing the function of the Lubricator 12.

FIG. 5 depicts the operational sequence of the pressure lock, as an item 60 such as a tool, sensor package, Centraliser or Skate is being injected into a well/pipeline. The upper seal 53 remains open for the majority of CT/Slickline or Wireline injecting operations, with lower seal 52 containing the wellbore/pipeline pressure (as shown in 61). An item is attached to the CT/Slickline or Wireline, which passes through the upper seal 53. The upper seal 53 closes once the item has entered the pressure lock body (as shown in 62). A valve 55 linking the wellbore/pipeline pressure with the pressure chamber opens to equalize the pressure either side of the lower seal 52. The embodiment depicted in FIG. 4 shows that the well bore pressure, which is used to equalize pressure either side of the packing elements through a connecting bore 42, is bled from the lower seal 52 through a valve 55, to a port 57 on the tube body. With pressure equalized the lower seal 52 opens to allow the item 60 to pass through, with the CT/Slickline or Wireline being stripped through the upper seal (as shown in 63). With the item 60 then through the pressure lock, the lower seal 52 closes (as shown in 64). The body of the pressure lock is safely vented/depressurized through a valve 56 to equalize pressure either side of the upper seal 53. In addition to venting, the body of the pressure lock could also be purged with an inert gas via an additional port. If any fluid is likely to enter the pressure lock, then the facility to safely drain these fluids could be added. With pressure either side of the upper seal 53 equalized it can reopen (as shown in 61), which completes the operational sequence for passing an item through during injection.

During CT/Slickline or Wireline recovery the operational sequence is similar, but with the majority of stripping done through the upper seal 53, and lower seal 52 normally open to allow returning items to enter the pressure lock. While the example embodiment has the majority of stripping operations during injection done through the lower seal 52, it could be done through the upper 53 (or even both). The same would be true for recovery operations, with majority of stripping possible through the lower seal 52 (or even both). Lower seal 52 would open once an item is about to enter, after closing (If not already) the upper seal 53 and equalizing pressure either side the lower 52. The item would pass into the pressure lock before again closing the lower seal 52 and equalizing the pressure either side of the upper seal 53. The upper seal would then open, and recovery with stripping done through the lower seal continued.

Some embodiments will incorporate sensors to track/indicate the position of items within the body of the pressure lock, and when items have cleared the sealing units so that they can safely be closed. Sensors enable the operation of passing an item through the pressure lock to be automated, and could be used in conjunction with the CT/Slickline or Wireline control system, stopping/pausing the injector if an item would be pulled against a closed sealing unit.

The present disclosure also relates to the attaching and detaching of items such as tools, sensor packages Centralisers and Skates. Rather than manually attaching and removing items to and from the CT/Slickline or Wireline using bolts or other fixings, it would be done using an automated attachment and removal machine 98 positioned above the pressure lock 97, and below the injector, as depicted in FIG. 9. In some embodiments using either a bayonet mechanism or sprung mechanism, which allows them to be quickly attached and released.

FIG. 6 shows what is known in the art as a bow spring Centraliser, but with the inventive incorporation of a bayonet-type quick attachment and release mechanism, which facilitates an automated attachment and removal. The Centraliser could be split into two halves that clamp together around the CT/Slickline or Wireline at either end. The lower clamp 73 is undersized to leave a gap 79, although saddle diameter matches that of CT/Slickline, so that when clamp halves are pushed together a clamp force between CT/Slickline and saddle is generated via bending in the saddle. The upper clamp 72 is slightly oversized, so that when the clamp halves are brought together there remains slight clearance between saddle and CT/Slickline, which allows the upper half of the Centraliser to slide axially as the bows are compressed.

When the two halves of the clamp are pushed together, the pin ratchets through the mechanism preventing the halves from being pulled apart. The embodiment of the mechanism shown in FIG. 6 has a plate 75 which is pivoted 77 on the clamp. A spring 76 keeps the plate 75 pushed against, and engaging with, the grooves in the pin 76. When the pin is pushed through, the taper on the pin groves pushes the plate back, which allows the pin to be pushed through, but not be pulled pack (ratchet type mechanism). As the clamp is pulled through the automated attachment machine, the plate 75 is squeezed, which disengages it from the pin 76 allowing clamp halves to be pulled apart.

The embodiment shown has stainless steel pins 76 built into plastic saddle halves, with the bows made from steel, although different materials and coatings could be used could be used for each component.

FIG. 7 shows what is known in the art as a Skate, but with the inventive incorporation of a quick attachment and release mechanism. The skate is a single piece split body rather than a clamp body attached to another for mounting the rollers, as has been done in the current art. The clamp halves which the rollers 87 are mounted are same as previously described 73. The material of both clamp, roller 87, and roller mounting 88 are likely to be steel due to weight of CT/Slickline or Wireline string, however, could use various materials and coatings depending on application. An example embodiment may use between 3 to 6 rollers per unit.

FIG. 8 shows an embodiment of that described for the quick attach/detach Centraliser in FIG. 6, but with the incorporation of rollers within the bow springs to reduce friction, essentially a Skate which would push against the well/pipeline to centralise rather than be undersized (smaller diameter than that of pipeline going through), as is the case with skates in the current art.

While the attachment of Centralisers and Skates will allow CT/Slickline or Wireline to be injected greater horizontal or inclined distances, or possibly through a more tortuous convoluted route than could be achieved without them, the position, spacing, and specification of Centraliser/Skate (load on each Centraliser/Skate may require a higher rating unit, or require increase in number of Centraliser/Skates to lower the load). For an algorithm for calculating the required Skate/Centraliser position and spacing along the CT/Slickline or Wireline, one example embodiment would be a computer program which the user would enter such parameters as desired final end position, well/pipeline profile (number of, position and tightness of bends, length of inclined/horizontal sections), well pressure, well fluid/gas properties (density, viscosity), well/pipeline ID, CT/Slickline or Wireline OD, thickness, and density (Including detail on possible tapering wall thickness), temperature, and injection speed. An example embodiment would use the required Skate/Centraliser positions attained from the program to set the automated attachment/removal machine of the second aspect, but could be used for manual Skate/Centraliser attachment.

For the case where tools or sensor packages are attached using the above embodiment, these tools and sensor packages would be recovered upon retrieval from the well and then their data recovered for analysis.

Although illustrative examples have been disclosed in detail herein, with reference to the accompanying drawings, it is understood that the invention is not limited to the precise embodiments shown and that various changes and modifications can be effected therein by one skilled in the art without departing from the scope of the invention as defined by the appended claims and their equivalents.

Claims

1. An apparatus for injecting or withdrawing items into or from a pressurized downhole, pipeline when carried on or by a tubular length comprising:

two or more pressure sealing units for sealing against the length as the item is injected, the sealing units being joined by a pressure lock section, the sealing units being movable between a sealed position in which they are sealing against the tubular length and a retracted position; and

means for controlling pressure in the pressure lock section, in which the sealing units can be selectively and sequentially moved from the sealed position to the retracted position to allow introduction of an item therethrough, and in which the pressure lock section is selectively pressurizable or depressurizable to allow the item to move from low to high or high to low pressure during injection or removal.

2. The apparatus of claim 1 wherein the tubular length is coiled tubing, slickline or wireline.

3. The apparatus as claimed in claim 1, wherein a diameter of the pressure lock section is greater than or equal to the diameter of a hole or pipeline being injected into.

4. The apparatus of claim 1, wherein the item comprises a tool, a sensor, a centralizer or a skate.

5. The apparatus of claim 4 wherein the centralizer comprises a quick-connect system.

6. The apparatus of claim 4 wherein the centralizer includes an axial restraint means.

7. The apparatus of claim 4 wherein the centralizer comprises or includes clamp means for clamping onto or around a tube, pipe, or cable.

8. The apparatus of claim 4 wherein the centralizer comprises two ends and one of the two ends provides axial restraint.

9. The apparatus of claim 1 further comprising an automatically attachable and detachable skate for a tube, pipe, or cable intended to be injected into a downpipe or pipeline.

10. The apparatus of claim 9, wherein the skate comprises two or more parts that can be clamped together on or around a tube, pipe, or cable.

11. The apparatus of claim 9 wherein the skate uses one or more of ratchets, bayonets, springs and magnets to attach on or around a tube, pipe, or cable.

12. The apparatus of claim 9 further comprising an apparatus for automatically attaching and removing the skate.

13. A method of injecting or removing items into or from a pressurized downhole, pipeline when carried on or by a tubular length, the method comprising the steps of:

a. providing two or more sealing units that seal against the length as the item is injected;

b. providing a pressure lock section which joins the sealing units;

c. moving a first, earlier sealing unit to a retracted position while a second, later unit is in a sealed position;

d. moving the item through the earlier sealing unit and into the pressure lock section;

e. closing the first sealing unit;

f. equalizing the pressure in the pressure lock section with the pressure beyond the later sealing unit;

g. moving the later sealing unit to a retracted position to allow the item to pass therethrough; and

h. moving the later sealing unit to a sealed position.

14. A method as claimed in claim 13, further comprising the steps of:

i. depressurizing the pressure lock section; and

j. moving the upstream sealing unit to a retracted position.

15. A method of removing items from a pressurized downhole, pipeline when carried on or by a tubular length, the method comprising the steps of:

providing two or more sealing units that seal against the length as it is withdrawn;

providing a pressure lock section which joins the sealing units;

moving a first, earlier sealing unit to a retracted position while a second, later unit is in a sealed position;

moving the item through the earlier sealing unit and into the pressure lock section; closing the first sealing unit;

equalizing the pressure in the pressure lock section with a lower pressure beyond a later sealing unit; and

moving the later sealing unit to a retracted position to allow the item to pass therethrough.

16. The method of claim 15 further comprising providing an automatically attachable and detachable centraliser for a tube, pipe, or cable intended to be injected into a downpipe, or pipeline.

17. The method of claim 16 wherein the centraliser comprises two or more parts that can be clamped together on or around a tube, pipe, or cable.

18. The method of claim 16 wherein the centraliser uses one or more of ratchets, bayonets, springs and magnets to attach on or around a tube, pipe, or cable.

19. The method of claim 15 further comprising providing a machine handlable chassis for detachably attaching items on a tube, pipe, cable intended to be injected into a downpipe or pipeline.

20. The method of claim 19 wherein the chassis uses one or more of ratchets, bayonets, springs and magnets to attach on or around a tube, pipe, or cable.

21. The method of claim 19 wherein the chassis is, forms part of or allows attachment of a centraliser, a tool, a sensor, or a skate.

22. A method for determining a required position and spacing of centralisers or skates along an injectable tube, the method taking into account one or more of the following criteria:

predicted final position;

well and pipeline profile;

number of, position and tightness of bends, length of inclined/horizontal sections,

well pressure profile along the well trajectory,

well fluid and gas properties,

well and pipeline inner diameter,

CT/Slickline or Wireline outer diameter and thickness

detail on possible tapering wall thickness of CT,

well temperature profile along the well trajectory, and

injection speed.