Note: Descriptions are shown in the official language in which they were submitted.
CA 02782874 2012-07-13
CIRCULATING COIL CLEANOUT TOOL AND METHOD
Field of the Invention
[0001] This invention relates to a downhole cleaning tool and method for
removing debris
from a well,
Background of the Invention
[0002] During production of oil from a well, debris such as sand, scale and
particulates may
clog the perforations at the bottom of the well, and accumulate with the
production fluids within
the wellbore, Such sand and debris can halt or hinder production, and damage
well equipment
by abrasion. It is thus important to be able to clean and remove such
undesirable materials from
the well as quickly and efficiently as possible.
[0003] The use of coiled tubing in wellbore cleanout technology is well-
established.
Conventional practices to remove debris include for example, equipment such as
concentric pipe,
tubing operated pump-to-surface bailer and coiled tubing with jetting;
engineering operations
supported with hydraulic modeling such as high-rate circulation, forward or
reverse circulation;
and use of carrier fluids with suspension capabilities.
[0004] However, such approaches arc often time-consuming, labour intensive,
and costly. The
required equipment is frequently mechanically complex which elevates the
possibility of
mechanical failure and costs for manufacture and repair.
[0005] Despite such advances, there remains a need for an effective method for
the removal of
debris from a well.
CA 02782874 2012-07-13
Summary of the Invention
100061 The present invention relates to a dovvnhole cleaning tool and method
for removing
debris from a well,
[0007] In one aspect, the invention provides a downhole tool for cleaning a
wellbore
comprising:
a) a tubing string comprising an upper end and a lower end, and defining a
first bore
for allowing passage of fluid from the wellbore to surface;
b) a guide string disposed inside the tubing string and defining an
internal bore to
run coiled tubing therethrough, the coiled tubing carrying at least one jet
nozzle;
c) at least one seal disposed around the tubing string for sealing against
a well
casing;
d) at least one port defined by the tubing string and positioned above the
seal for
allowing fluid to pass therethrough; and
e) at least one valve positioned below the seal to allow fluid to pass
upward through
the valve but not downward.
[0008] In one embodiment, the seal comprises at least one ring-shaped V cup
having an
interior diameter substantially equal to the outside diameter of the tubing
string. In one
embodiment, the seal comprises a pair of stacked V cups, an upper V cup being
oriented
upwardly and a lower V cup being oriented downwardly.
[0009] In one embodiment, the tubing string defines a pair of aligned,
parallel spaced ports. In
one embodiment, the valve comprises a ball valve. In one embodiment, the
tubing string and
guide string are threadless. In one embodiment, the guide string is sealed at
its lower end. In
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one embodiment, a drain or a sliding sleeve is positioned between the seal and
the valve. In one
embodiment, the guide string and valve are optional components.
[00010] In another aspect, the invention provides a method of cleaning a
wellbore using the
above tool comprising the steps of:
a) running the tool into the wellbore in proximity to perforations;
b) pumping circulation fluid into an annulus defined between the tool and
well
casing under sufficient pressure to force the circulation medium upwardly
through the port into
the tubing string to surface, wherein formation fluid and debris are suctioned
upwardly into the
tubing string;
c) running coiled tubing into the guide string to position the jet nozzle
in proximity
to the perforations;
d) pumping cleaning fluid into the coiled tubing to create a jet stream of
fluid; and
e) continuously pumping the circulation medium and cleaning fluid for
conveying
formation fluid and debris upwardly from the wellbore to surface.
[00011] In one embodiment, the guide string and valve are omitted from the
tool.
[00012] In one embodiment, the method further comprises running a profile
nipple into the
wellbore to land a blanking plug. In one embodiment, the method further
comprises killing the
wellbore and removing the tool from the killed wellbore. In one embodiment,
kill fluid is
pumped into the tubing string to blow a drain. In one embodiment, a sliding
sleeve is actuated to
allow fluid drainage.
[00013] Additional aspects and advantages of the present invention will be
apparent in view of
the description, which follows. It should be understood, however, that the
detailed description
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and the specific examples, while indicating preferred embodiments of the
invention, are given by
way of illustration only, since various changes and modifications within the
spirit and scope of
the invention will become apparent to those skilled in the art from this
detailed description.
Brief Description of the Drawings
[00014] The invention will now be described by way of an exemplary embodiment
with
reference to the accompanying simplified, diagrammatic, not-to-scale drawings.
In the drawings:
[00015] Figure 1A is a diagrammatic representation of an embodiment of the
invention.
[00016] Figure 1B is a diagrammatic representation of a transverse cross-
sectional view taken
along line 1A-1A of Figure 1A.
[00017] Figure 2 is a diagrammatic representation of an embodiment of the
invention in an
actuation position with a well.
Detailed Description of Preferred Embodiments
[00018] When describing the present invention, all terms not defined herein
have their
common art-recognized meanings. To the extent that the following description
is of a specific
embodiment or a particular use of the invention, it is intended to be
illustrative only, and not
limiting of the claimed invention. The following description is intended to
cover all alternatives,
modifications and equivalents that are included in the spirit and scope of the
invention, as
defined in the appended claims.
[00019] The present invention will now be described having reference to the
accompanying
figures. The invention provides a downhole cleaning tool and method for
removing debris from
a well with minimal hydrostatic pressure being placed on the formation. The
tool and method
enable injection of cleaning fluid through coiled tubing for lifting formation
fluid and debris
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from the wellbore. A suitable fluid is also circulated to provide enhanced
lift for cleaning and
removal.
[00020] A conventional gas well typically comprises a wellbore extending from
the surface
through the earth to intersect a production formation to produce natural gas,
condensate (i.e.,
natural gas liquids such as propane and butane) and occasionally water.
Similarly, an oil well
typically varies from a few hundred to several thousand feet in depth. The
tool may be placed in
vertical, horizontal or inclined wellbores, "Horizontal" means a plane that is
substantially
parallel to the plane of the horizon. "Vertical" means a plane that is
perpendicular to the
horizontal plane. Such variations of well design are known to those skilled in
the art.
[00021] The tool (1) is generally shown in the Figures to include a tubing
string (10), a guide
string (12), a pair of seals (14a, 14b), at least one port (16), and at least
one valve (18). Figure 2
shows the tool (1) mounted within the well tubular in a concentric
orientation, for example, the
production casing (32) of a conventional well to contact the wellbore fluid.
As used herein, the
term "concentric" refers to components sharing a common center and thus a
substantially
uniform annular dimension. However, one skilled in the art will recognize that
two tubular
members where one has a smaller diameter and is placed within the other may be
considered
concentric, even if they do not share the exact geometric centre, and even if
they are not circular
in cross-section.
[00022] The tubing string (10) comprises an upper end (20) which extends to
the surface, and
a lower end (22) which extends downhole. The tubing string (10) may generally
be cylindrical
and defines a first bore (24) which allows passage of circulation medium
(indicated by arrow
"a") from the annulus (34); and formation fluid and debris (indicated by arrow
"b"), and a
mixture of cleaning fluid, formation fluid and debris (also indicated by arrow
"b") from the
wellbore (42) to the surface.
[00023] The tool (1) provides convenient access for running coiled tubing (not
shown) into the
wellbore (42) by provision of the guide string (12), The guide string (12) is
generally cylindrical
and defines an internal bore (26) sized to accommodate the coiled tubing which
is run
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therethrough during operation. The guide string (12) is disposed inside the
tubing string (10)
using suitable fastening means (28) as are known in the art.
[00024] In one embodiment, the guide string (12) may be scaled at its lower
end (30). The
sealing of the guide string (12) prevents the entry of formation fluid and
debris into the guide
string (12) from the wellbore (42) when the coiled tubing is not required.
[00025] Coiled tubing is typically inserted into a completed oil wellbore for
various operations
including, but not limited to, chemical injection, servicing, and transport of
bottom hole
assemblies. In one embodiment, a jet nozzle (not shown) is attached to the
coiled tubing in a
conventional manner,
[00026] At least one seal (14a, 14b) is disposed around the tubing string
(10). The seal (14a,
14b) is sized so as to seal the tubing string (10) against the well casing
(32). Suitable seals (14a,
14b) as are known in the art may be used. The seals (14a, 14b) may be formed
of, for example,
synthetic rubbers, thermoplastic materials, perfluoroelastomer materials, or
other suitable
substances known to those skilled in the art. Appropriate seals (14a, 14b) are
sufficiently
resilient for providing a good seal and sufficiently rigid for providing a
relatively long life
therefore, The dimensions of the seals (14a, 14b) are not essential to the
invention and are
dictated by the sizes of the tubing string (10) and well casing (32).
[00027] In one embodiment, the seal comprises an upper ring-shaped V cup (14a)
and a lower
ring-shaped V cup (14b). Each V cup (14a, 14b) has an interior diameter
substantially equal to
the outside diameter of the tubing string (10). The outer diameter of the V
cup (14a, 14b) is
substantially equal to the diameter of the well casing (32). Each V cup (14a,
14b) is a resiliently
flexible disk shaped body having a central hole. The diameter of the central
hole is substantially
equal to the outer diameter of the tubing string (10) such that the V cup
(14a, 14b) is placed
around the tubing string (10) in a collar-like manner. The walls of the V cup
(14a, 14b) extend
radially from the central hole at an angle below the horizontal plane of the
central hole such that
the outer edge of the V cup (14a, 14b) terminates at a position below the
plane of the central
hole, The upper V cup (14a) and lower V cup (14b) are oriented in a stacked
relationship. The
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CA 02782874 2012-07-13
upper V cup (14a) is orientated so that the cup walls extend radially upwardly
towards the
surface. The lower V cup (14b) is orientated so that the cup walls extend
radially downwardly
towards the downhole.
[00028] The tool (1) includes one or more ports (16). In one embodiment, the
tubing string
(10) defines a pair of aligned, parallel spaced ports (16). The ports (16) are
positioned above the
seals (14a, 14b) to allow entry of the circulation medium ("a") from the
annulus (34) into the
tubing string (10). The ports (16) provide an escape route above the upper V
cup (14a) for the
circulation medium ("a") which has been injected into the annulus (34).
[00029] The tubing string (10) includes at least one valve (18) positioned
below the seals (14a,
14b). The valve (18) is one-way, allowing fluid to pass upward through the
valve (18) but not
downward. In one embodiment, the valve (18) comprises a ball valve. It will be
understood by
those skilled in the art that other suitable valves may be used, interchanged,
or selected in
accordance with the type of fluid being pumped; for example, a ball valve may
be used with
lighter fluids and in the absence of solid particulate material, while a
hinged valve or a flapper
valve may be used with heavy oil or sand.
[00030] The tool (1) can be constructed from any material or combination of
materials having
suitable properties such as, for example, mechanical strength, ability to
withstand cold and
adverse field conditions, corrosion resistance, and ease of machining.
[00031] The tool (1) may be manufactured as either an integral body or a
composite tool. In
one embodiment, the tubing string (10), guide string (12), ports (16), and
valve (18) are
combined in an integral body. As used herein, the term "integral" means that
the body portion of
the tubing string (10) is formed from a single cast or forged steel body which
is machined to
form the guide string (12), ports (16) and valve (18). With respect to the
seals (14a, 14b), the
body portion is sized and adapted to mount the seals (14a, 14b).
[00032] In one embodiment, the tubing string (10) and the guide string (12)
are both
threadless. As used herein, the term "threadless" means free of cooperating
threads to
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interconnect components as they are aligned and rotated relative to one
another. The use of a
threadless tubing string (10) and guide string (12) minimizes friction and
restriction of fluid flow
within the annulus (34) during operation. The threadless configuration
provides a reliable
method for straight-pull emergency shear release. A shear is effectively built
into the tubing
string (10) to enable positive release of the tubing string (10) in the event
that the tool (1)
becomes stuck within the wellbore (42). A relatively large work string may
also be used
including one or more substantially large ports (16) for circulating fluids up
the tubing string
(10) and allowing more inflow with less restriction from the desired cleaning
zone.
[00033] However, those skilled in the art will understand that various
modifications can be
made without altering the substance of the invention. For example, the tool
(1) may be formed
from the assembly of separate components which may be threaded.
[00034] In one embodiment, the guide string (12) and valve (18) are optionally
omitted from
the tool (1) in the event that the tubing string (10) may have an internal
diameter which is
insufficient to accommodate a guide string (12). In this configuration, the
tubing string (10) is
sized to accommodate coiled tubing which is appropriately sized to be easily
run into or removed
from the tubing string (10).
[00035] Use of the tool (1) will now be described having reference to Figure
2. A suitable
configuration for well control includes fluid injection inlets (36) having
valves (38) which can be
opened and closed to permit and cease the flow of fluid, and a blow-out
preventer (40) which
prevents the tool (1) from being blown out of the wellbore (42) when a blowout
threatens.
Positioning of the guide string (12) inside the tubing string (10) thus allows
the blow-out
preventer (40) to close around both the tubing string (10) and guide string
(12) to prevent them
from being blown out of the wellbore (42). In one embodiment, the blow-out
preventer (40)
comprises one or more variable bore-pipe rams which accommodate tubulars of
varying
diameters and through which the tubulars are tripped. Ported crossover bodies
may be used for
picking up work string.
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[00036] The tool (1) is run through the blowout preventer (40) into the
wellbore (42) using
conventional techniques and positioned in proximity to a plurality of
perforations (44) which are
diametrically opposed and spaced intermittently along the casing (32) adjacent
an underground
formation (46) to enable fluid communication with the formation (46). As used
herein, the term
"debris" means debris which generally exists in the formation (46) and in the
casing (32), and
results from operations including drilling or perforation debris, debris from
cementing
operations, and from mud solids. Naturally occurring debris such as sand,
silts or clays may also
be present in the formation (46).
[00037] The upper and lower V cups (14a, 14b) of the tool (1) are in a sealing
engagement
with the casing (32). Above the upper V cup (14a), an annulus (34) is defined
between the tool
(1) and the casing (32). The tool valve (18) is in the closed position. The
casing valves (38) are
opened to allow pumping of circulation medium ("a") under pressure through the
inlets (36) into
the annulus (34). The upper V cup (14a) acts as a physical barrier between the
tool (1) and
casing (32) to prevent the circulation medium ("a") from flowing further
downward through the
annulus (34). Upon reaching the upper V cup (14a), the circulation medium
("a") is forced
upwardly through the ports (16) into the tubing string (10).
[00038] The circulation medium ("a") which is pumped into the annulus (34) may
comprise
any suitable medium including, but are not limited to, drilling fluid, water-
based fluids, foaming
agents, and the like. In one embodiment, the circulation medium comprises low
density foam.
Foam inherently has a high viscosity at low shear rates making it extremely
useful as a
circulating medium. A variety of natural and process additives or polymers are
known in the art
to increase the lifting, carrying, and suspending capability of the
circulation medium.
[00039] It is to be noted that the upper V cup (14a) prevents any hydrostatic
pressure from
being placed on the formation (46) since the vertical height of the
circulation medium ("a") is
minimal above the perforations (44) when pumping or at rest. As used herein,
the term
"hydrostatic pressure" means the total fluid pressure created by the weight of
a column of fluid,
acting on any given point in a well.
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[00040] The upwards motion of the circulation medium ("a") into the tubing
string (10)
creates a Venturi effect and suctioning force which draws formation fluids and
debris ("b") from
the formation (46) through the perforations (44). The upwards motion of the
formation fluid and
debris ("b") opens the tool valve (18) to pass into the tubing string (10).
The lower V cup (14b)
acts as a physical barrier to prevent the formation fluid and debris ("b")
from flowing upwards
into the annulus (34), and to force the formation fluid and debris ("b") to
flow upwards through
the tool valve (18) into the tubing string (10) to be circulated to the
surface.
[00041] Once circulation has been established, coiled tubing (not shown) is
run into the guide
string (12) using conventional coiled tubing techniques including, but not
limited to, a kick off
coil diverter. The guide string (12) facilitates insertion of the coiled
tubing and access to the
wellbore (42). Further, the guide string (12) provides stability and rigidity
to the coiled tubing
by preventing the coiled tubing from bending or wrapping around the tubing
string (10).
Agitation of sand around the coiled tubing is minimized. Further, the guide
string (12) simply
and effectively expedites the entry and removal of the coiled tubing from the
wellbore (42) since
the amount of drag is minimized.
[00042] The coiled tubing is positioned below the tool (1) in proximity to the
perforations
(44). Cleaning fluid is pumped under pressure through the coiled tubing and a
bottom hole
assembly (not shown). In one embodiment, the bottom hole assembly comprises a
jet nozzle
which emits a stream of pressurized fluid at a relatively high velocity. The
pressurized fluid
stream facilitates the clean out of the perforations (44), slots, and screens,
and the suspension of
the formation fluid and debris ("b") within the cleaning fluid. As the
circulation of circulation
medium ("a") continues, the suspension of cleaning fluid, formation fluid, and
debris is drawn
upwardly through the valve (18) into the tubing string (10). The suspension of
cleaning fluid,
formation fluid, and debris combines with the circulation medium ("a") for
conveyance to the
surface. The clean out of the wellbore (42) is thus achieved by synchronizing
the pumping of
cleaning fluid through the coiled tubing with the continuous pumping of the
circulation medium
("a") into the annulus (34) to generate the desired downhole action.
CA 02782874 2012-07-13
[00043] The cleaning fluid ("b") which is pumped through the coiled tubing may
comprise any
suitable fluid to clean different kinds of sand and scales, and to remove wax
or asphaltene build-
up. Suitable fluids may include, but are not limited to, water- or oil-based
fluids, water/brine,
diesel/base oil, friction-reduced fluids, acids, surfactants, polymer gels,
foaming agents, and the
like.
[00044] Upon completion of the cleaning operation, the coiled tubing is
withdrawn up through
the guide string (12) for removal. A profile nipple (not shown) may be run
into the wellbore (42)
to land a blanking plug to prevent re-circulation of well fluids, thereby
shutting in the well. The
tubing string (10) and guide string (12) can be snubbed out.
[00045] It may be desirable to circulate kill fluid into the wellbore to stop
the flow of the
formation fluid. As used herein, the term "kill fluid" means any liquid pumped
into a well to
stop a kick (i.e., influx of formation fluid), The kill fluid is usually kill
mud which is a weighted
drilling mud. In one embodiment, the tubing string (10) may include a drain
(not shown)
positioned between the lower V cup (14b) and valve (18), and responsive to
pressure. A kill
fluid having sufficient density to overcome production of the formation fluid
is pumped into the
tubing string (10) to stop the flow and to blow the drain, resulting in
draining of both the tubing
string (10) and annulus (34) between the tool (1) and the casing (32) prior to
tripping the tubulars
out of the wellbore (42). In one embodiment, the tubing string (10) may
include a sliding sleeve
(not shown) positioned between the lower V cup (14b) and valve (18). As are
known in the art,
sliding sleeves include ports which can be opened or closed by a sliding
component that is
generally controlled and operated by a slickline tool string to allow the
opening or closure of
flow from a zone or communication from tubing to annulus. The sliding sleeve
may be actuated
to allow fluid drainage from the tubing string (10) and annulus (34). It will
be recognized by
those skilled in the art that any suitable sliding sleeve as are known in the
art would be
appropriate for use with the present invention. The draining operation avoids
problems
commonly associated with pulling wet strings. The tool (1) is then withdrawn
up through the
blowout preventer (40) for removal from the wellbore (42).
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[00046] In one embodiment, the invention provides a method of cleaning a
wellbore using the
tool comprising running the tool into the wellbore in proximity to
perforations; pumping
circulation fluid into an annulus defined between the tool and well casing
under sufficient
pressure to force the circulation medium upwardly through the port into the
tubing string,
wherein formation fluid and debris are suctioned upwardly into the tubing
string; running coiled
tubing into the guide string to position the jet nozzle in proximity to the
perforations; pumping
cleaning fluid into the coiled tubing to create a jet stream of fluid; and
continuously pumping the
circulation medium and cleaning fluid for conveying formation fluid and debris
up the wellbore
to surface.
[00047] As will be apparent to those skilled in the art, various
modifications, adaptations and
variations of the foregoing specific disclosure can be made without departing
from the scope of
the invention claimed herein.
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