U.S. patent application number 14/688680 was filed with the patent office on 2015-10-22 for live well injection.
The applicant listed for this patent is REECE INNOVATION CENTRE LIMITED. Invention is credited to Ross James Lamonby, James Edward Martin, Alexander James Wilkinson.
Application Number | 20150300106 14/688680 |
Document ID | / |
Family ID | 54321576 |
Filed Date | 2015-10-22 |
United States Patent
Application |
20150300106 |
Kind Code |
A1 |
Martin; James Edward ; et
al. |
October 22, 2015 |
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.
Inventors: |
Martin; James Edward;
(Whitley Bay, GB) ; Wilkinson; Alexander James;
(Newcastle, GB) ; Lamonby; Ross James;
(Northumberland, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
REECE INNOVATION CENTRE LIMITED |
Newcastle upon Tyne |
|
GB |
|
|
Family ID: |
54321576 |
Appl. No.: |
14/688680 |
Filed: |
April 16, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61980992 |
Apr 17, 2014 |
|
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|
Current U.S.
Class: |
166/382 ;
166/244.1; 166/77.1 |
Current CPC
Class: |
E21B 17/1028 20130101;
E21B 17/1057 20130101; E21B 33/068 20130101; E21B 33/072
20130101 |
International
Class: |
E21B 19/22 20060101
E21B019/22; E21B 33/068 20060101 E21B033/068; E21B 33/072 20060101
E21B033/072; E21B 19/24 20060101 E21B019/24 |
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.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] 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
[0002] The present disclosure relates generally to the injection of
tubes, pipes, cables and the like into pressurized downholes,
wells, pipelines and the like.
BACKGROUND
[0003] 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.
[0004] 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.
[0005] 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.
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] The term "tubular length" may mean, for example, CT,
Slickline and Wireline, drill pipe and the like.
[0013] 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.
[0014] The method may further comprise the steps of: depressurising
the pressure lock section; and moving the upstream sealing unit to
a retracted position.
[0015] 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.
[0016] 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.
[0017] 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.
[0018] The system may be installed as the top/first component of
the pressure retaining stack or other such pressure control
equipment.
[0019] 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.
[0020] In some embodiments the apparatus consists of only two
sealing units and one pressure lock section.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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,
[0027] The centraliser may comprise two or more parts that can be
clamped together on or around a tube, pipe, cable or the like.
[0028] The present disclosure also provides apparatus for
automatically attaching and/or removing the centraliser as
described herein.
[0029] 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,
[0030] The skate may comprise two or more parts that can be clamped
together on or around a tube, pipe, cable or the like.
[0031] 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,
[0032] 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.
[0033] 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.
[0034] The present disclosure also provides an apparatus for
automatically attaching and/or removing the skate as described
herein.
[0035] 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.
[0036] 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.
[0037] A further aspect provides apparatus for automatically
attaching and/or removing the centraliser described herein.
[0038] 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.
[0039] A further aspect provides apparatus for automatically
attaching and/or removing the skate described herein.
[0040] A further aspect provides an automated machine for attaching
and/or removing items to/from an injectable downpipe tube.
[0041] 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.
[0042] A further aspect provides a centraliser comprising a
quick-connect system.
[0043] 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.
[0044] The present disclosure also provides a pipeline, downhole or
the like system including apparatus as claimed and described
herein.
[0045] 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.
[0046] 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.
[0047] 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.
[0048] 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: [0049]
predicted final position; [0050] well/pipeline profile; [0051]
number of, position and tightness of bends, length of
inclined/horizontal sections, [0052] well pressure profile along
the well trajectory, [0053] well fluid/gas properties, [0054]
well/pipeline ID, [0055] CT/Slickline or Wireline OD and thickness
[0056] detail on possible tapering wall thickness of CT, [0057]
well temperature profile along the well trajectory, [0058]
injection speed.
[0059] 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.
[0060] Further embodiments are disclosed in the dependent claims
attached hereto.
[0061] Different aspects and embodiments of the disclosure may be
used separately or together.
[0062] 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
[0063] The present invention will now be more particularly
described, with reference to the accompanying drawings, in
which:
[0064] FIG. 1A and FIG. 1B show silhouettes of example coiled
tubing stacks attached to production Christmas trees;
[0065] FIG. 2 shows an example axial compression stripper;
[0066] FIG. 3 shows an example radial stripper;
[0067] FIG. 4 is a schematic representation of an injection
apparatus formed according to an exemplary aspect;
[0068] FIG. 5A to FIG. 5D show the operation of the apparatus of
FIG. 4;
[0069] FIG. 6A to 6D show a centraliser formed according to a
further aspect;
[0070] FIG. 7A to 7D show a skate formed according to a further
aspect;
[0071] FIG. 8 shows a centraliser formed according to a further
embodiment; and
[0072] FIG. 9 is a schematic representation of an automated
attachment/removal machine.
DETAILED DESCRIPTION
[0073] 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.
[0074] 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.
[0075] 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.
[0076] 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.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
[0082] 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.
[0083] 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.
[0084] 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.
[0085] 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.
[0086] 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.
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