Note: Descriptions are shown in the official language in which they were submitted.
CA 02641778 2008-10-14
1
TITLE
[0001] Method And Apparatus For Use In Selectively Fracing A Well
FIELD
[0002] There is disclosed a method and apparatus for placing multiple
fractures at spaced
locations along a well bore.
BACKGROUND
[0003] U.S. Patent 7,267,172 (Hofman) entitled "Cemented Open Hole Selective
Fracing
System" teaches selectively opening holes in production tubing of a
hydrocarbon producing
well by using sliding valves which can be selectively opened by a shifting
tool. U.S. Patent
7,096,954 (Weng et al) entitled "Method and Apparatus for Placement of
Multiple Fractures
in Open Hole Wells" teaches using a plurality of burst disk assemblies, each
having an
independent burst pressure. The present method provides an alternative method
of selectively
opening holes in production tubing.
SUMMARY
[0004] There is provided an apparatus for use in selectively fra.cing a well.
The apparatus
comprises a tubular body having an exterior surface, and an interior surface
that defines an
interior bore. An annular flow area that has at least one fluid flow port
extends radially
through the tubular body from the interior surface to the exterior surface to
permit fluids from
the interior bore to pass through the at least one fluid flow port into a
surrounding earth
fonnation. An external sealing sleeve is detachably secured to the exterior
surface of the
tubular body to selectively cover the annular flow area and close the at least
one fluid flow
port. There is a pressure actuated sleeve shifting mechanism, with increasing
pressure
tending to cause axial movement of the external sealing sleeve. Axial movement
is resisted
until a pre-selected pressure threshold is reached to permit movement of the
external sealing
sleeve to open the at least one fluid flow port.
[0005] There is also provided a method for use in selectively fracing a well
comprising
the following steps: (a) providing a plurality of apparatus as described
above; (b) deploying
the apparatuses along a production tubing string in a well with packers being
positioned
CA 02641778 2008-10-14
2
between the apparatuses to isolate production areas, the pre-selected pressure
threshold for
each production area increasing from a toe of the well toward a heel of the
well; (c) pumping
fluids down the production tubing at pressures just sufficient to selectively
shift the external
sealing sleeve of the apparatus having a lowest shifting pressure to an open
position without
shifting the external sealing sleeve of others of the apparatus having higher
shifting pressures;
(d) continuing to pump fluids down the production tubing to pump fluids into
the earth
formation through the apparatus that has had its external sealing sleeve moved
to the open
position; (e) pumping balls down the production tubing until the balls seat on
and close the at
least one fluid flow port on the apparatus that has had its external sealing
sleeve moved to the
open position; (f) using fluid pressure to maintain the balls seated on the at
least one fluid
flow port while other of the externat sealing sleeves in the production tubing
are selectively
moved to the open position; and (g) repeating steps (c), (d), (e) and ( fl to
selectively open the
external sealing sleeve in apparatus in the production tubing in stages.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] These and other features will become more apparent from the following
description in which reference is made to the appended drawings, the drawings
are for the
purpose of illustration only and are not intended to be in any way limiting,
wherein:
FIG. 1 is a side elevation view in section of an apparatus for selectively
fracing a
well.
FIG. 2 is an end elevation view in section of a sealing sleeve of the
apparatus
depicted in FIG.1.
FIG. 3 is a detailed side elevation view of the sealing cavity of the fluid
cavity of
FIG.1.
FIG. 4 is a side elevation view in section of the sealing sleeve in the open
position.
FIG. 5 is a side elevation view in section of the flow ports plugged with
balls.
FIG. 6 is a side elevation view of the apparatus depicted in FIG. 1 installed
in a
tubing string and inserted into a well.
FIG. 7 is a side elevation view in section of an alternative tubular body.
FIG. 8 is a side elevation view in partial section of an isolation tool.
FIG. 9 is a side elevation view in partial section of the isolation tool
adjacent to
CA 02641778 2008-10-14
3
the apparatus depicted in FIG. 1.
DETAILED DESCRIPTION
[0007] An apparatus for use in selectively fracing a well generally identified
by reference
numeral 10, will now be described with reference to FIG.1 through 4. The use
and operation
of the apparatus will then be discussed with reference to FIG. 1 through 6, 8
and 9. An
alternative tubular body will be described with reference to FIG. 7.
Structure and Relationship of Parts:
[0008] Referring to FIG. 1, apparatus 10 includes a tubular body 12 that has
an exterior
surface 14 and an interior bore 16 defined by an interior surface 17. An
annular flow area 18
has one or more fluid flow ports 20 extending radially through tubular body 12
from interior
surface 17 to exterior surface 14. In FIG. 1, three flow ports 20 are included
and in FIG. 2,
the sealing sleeve 24 is designed to cover three. It will be understood that
the number may be
varied during construction of apparatus 10, according to the preferences of
the user or
manufacturer. Fluid flow ports 20 permit fluids from interior bore 16 to pass
through fluid
flow ports 20 into a surrounding earth formation.
[0009] Referring to FIG. 1 and 2, an external sealing sleeve 24 is detachably
secured to
exterior surface 14 of tubular body 12 to selectively cover annular flow area
18 and close
fluid flow ports 20. External sleeve 24 has a first end 26 with a first
internal diameter that
engages a first sealing area 28 on exterior surface 14 of tubular body 12 on a
first side 30 of
annular flow area 18. External sleeve has a second end 32 with a second
internal diameter
that engages a second sealing area 34 on exterior surface 14 of tubular body
12 on a second
side 36 of annular flow area 18. In the depicted embodiment, first sealing
area 28 and second
sealing area 34 have first and second seal grooves 38 and 40 in which are
positioned first and
second 0-ring seals 42 and 44, respectively. A locking engagement is
preferably provided
between external sealing sleeve 24 and exterior surface 14 of tubular body 12
to lock external
sealing sleeve 24 in the open position as shown in FIG. 4. For example, as
depicted in FIG.
3, several resilient fingers 52 may be carried by external sealing sleeve 24.
Resilient fingers
52 would then engage an engagement profile 54 on exterior surface 14 of
tubular body 12 to
maintain external sealing sleeve 24 in the open position.
CA 02641778 2008-10-14
4
[0010] Preferably, external sealing sleeve 24 is detachably secured to
exterior surface 14
of tubular body 12 by shear pins 46 in shear pin apertures 47. Exterior
surface 14 of tubular
body 12 has a circumferential shear pin groove 48 to accommodate shear pins
46. Shear pins
46 are designed to shear and permit external sealing sleeve 24 to move as
pressure builds
within annular flow area 18 and reaches a predetermined pressure threshold. In
a preferred
embodiment, the number of shear pins 46 is adjustable, which permits a user to
select a pre-
selected pressure threshold at which the external sealing sleeve 24 is able to
move by using a
greater number or fewer number of shear pins 46.
[0011] External sealing sleeve 24 is moved by applying pressure to a pressure
actuated
sleeve shifting mechanism. For example, as shown in FIG. 3, extemal sealing
sleeve 24 is
shifted by applying pressure within a fluid cavity 50 that is formed between
external sealing
sleeve 24 and exterior surface 14 of tubular body 12. Fluid cavity 50 is
asymmetrical to
provide an asymmetrical pressure distribution, so that increasing pressure
within fluid cavity
50 tends to cause axial movement of external sealing sleeve 24. In another
example shown in
FIG. 9, external sealing sleeve 24 may also be shifted by applying pressure to
an inclined
plane 51 located at the end of fluid flow port 20. As pressure builds within
this fluid flow port
extension 50, pressure acts against tapered wall 51 and pushes sealing sleeve
24 axially along
apparatus 10. In either example, axial movement is resisted until a pre-
selected pressure
threshold is reached, such as by using shear pins 46 as described above. Once
the pre-
selected pressure threshold is reached, movement of external sealing sleeve 24
is permitted to
open fluid flow ports 20.
[0012] It will be understood that other pressure actuated sleeve shifting
mechanisms may
be used, including different release mechanisms. For example, sleeve 24 may be
biased to the
shifted, open position, and a pressure increase may release a catch that
allows sleeve 24 to
shift.
Operation:
[0013] Referring to FIG. 6, apparatuses 10 are deployed along a production
tubing string
53 with packers 55, such as hydraulically set dual element open hole packers.
The type of
CA 02641778 2008-10-14
packer used will be selected based on the conditions and preferences of the
user. As
apparatuses 10 are intended to be used downhole, they may be hard coated with
carbide seats
to improve durability. Referring to FIG. 1, each apparatus 10 is prepared by
positioning
external sealing sleeve 24 over annular flow area 18 such that flow ports 20
are blocked.
5 External sealing sleeve 24 is then locked into the closed position by
inserting a certain
number of shear pins 46 that engage shear pin groove 48. The number of shear
pins 46 sets
the pressure at which external sealing sleeve 24 will move, such that, by
increasing the
number of shear pins 46, the pre-determined pressure also increases. Referring
again to FIG.
6, packers 55 are positioned between apparatuses 10 to isolate the desired
production areas.
Tubing string 53 is then inserted into the casing 56 of a wellbore 58, in this
case, a horizontal
wellbore, such that each apparatus 10 is aligned with the portion of the
formation to be fraced.
[0014] Once tubing string 53 is positioned with packers 55 set, fluids are
pumped down
tubing string 53 at pressures just sufficient to selectively shift external
sealing sleeve 24 of
apparatus 10 having the lowest pre-determined shifting pressure to an open
position as shown
in FIG. 3, such that fingers 52 engage profile 54, without shifting other
external sealing
sleeves 24 that have higher shifting pressures. Fluids are continued to be
pumped down
production tubing 53 to pump fluids into the earth formation through apparatus
10 that has
had its external sealing sleeve 24 moved to the open position to treat the
formation. Once
treated, balls 60 are then pumped down tubing 53 until balls 60 seat on, and
close fluid flow
ports 20 on the open apparatus 10 as shown in FIG. 5. Fluid pressure is
maintained to keep
balls 60 seated on fluid flow ports 20. Fluid pressure is then increased until
the next pre-
determined pressure threshold is met to move the desired external sealing
sleeve 24 to the
open position. These steps are repeated to selectively open the desired
external sealing
sleeves 24 in the desired order, generally by starting toward the toe 62 and
working toward
the heel 64 if the well is a horizontal wellbore, or from the end of the
wellbore and working
backward.
[0015] The operation steps above are based on using differential pressures to
open
selected sealing sleeves 24. It has been found that in some circumstances, the
flow ports 20
closest to the wellhead may become washed out by the abrasives, and become
unusable. It
will be understood other methods may also be employed, and may be preferable
in some
CA 02641778 2008-10-14
6
circumstances. For example, referring to FIG. 8, an isolation tool 70 may be
used to apply
pressure to a specific portion of tubing string 53 shown in FIG. 6. Isolation
too170 may be a
cup frac tool, which is used to selectively frac a portion of a formation.
Isolation tool 70 has
an input 72 in fluid communication with an output or fluid flow ports 74, with
sealing
elements 76 positioned on either side of fluid flow ports 74. Input 72 is
connected to another
tubing string (not shown) that extends to the surface, such that fluid
pressure may be applied
by pumping fluid through the tubing string and out outputs 74, as shown by
arrows 78.
Isolation tool 70 is inserted into tubing string 53 until fluid flow ports 20
of a selected
apparatus 10 are positioned between sealing elements 76. Referring to FIG. 9,
sealing
elements 76 engage interior surface 17 such that the fluid pressure is applied
to the selected
fluid flow ports 20. Once the fluid pressure causes external sealing sleeve 24
to shift as
described above, pressure is continued to be applied to frac the portion of
the formation
corresponding to those ports 20. This method negates the need for providing
increasing
opening pressures for each apparatus 10, as well as the need to pump balls
down tubing string
53 to plug the opened fluid flow ports 20. It also reduces the risk of ports
20 becoming
prematurely washed out. Once the frac is complete for that section, isolation
tool 70 is
repositioned at the next set of fluid flow ports, and the process is repeated.
Variations
[0016] FIG. 7 shows a slightly modified tubular body 12. Compared with FIG. 1,
tubular body 12 has been lengthened. This has the effect of locking external
sealing sleeve 24
(not shown) further from flow ports 20. In addition, instead of a shoulder
that is engaged,
profile 54 is a groove. This allows tubular body 12 to have a thicker sidewall
past profile 54.
Finally, tubular body has a slightly angled surface 66 between seal groove 40
and shear pin
groove 48. While not shown, external sealing sleeve 24 will also have a
corresponding angled
surface 66.
[0017] In this patent document, the word "comprising" is used in its non-
limiting sense to
mean that items following the word are included, but items not specifically
mentioned are not
excluded. A reference to an element by the indefinite article "a" does not
exclude the
possibility that more than one of the element is present, unless the context
clearly requires that
there be one and only one of the elements.
CA 02641778 2008-10-14
7
[0018] The following claims are to be understood to include what is
specifically
illustrated and described above, what is conceptually equivalent, and what can
be obviously
substituted. Those skilled in the art will appreciate that various adaptations
and modifications
of the described embodiments can be configured without departing from the
scope of the
claims. The illustrated embodiments have been set forth only as examples and
should not be
taken as limiting the invention. It is to be understood that, within the scope
of the following
claims, the invention may be practiced other than as specifically illustrated
and described.
