U.S. patent application number 15/960770 was filed with the patent office on 2018-08-23 for multi-stage well isolation and fracturing.
The applicant listed for this patent is Resource Completion Systems Inc.. Invention is credited to John Hughes, Ryan D. Rasmussen, James W. Schmidt.
Application Number | 20180238142 15/960770 |
Document ID | / |
Family ID | 50263165 |
Filed Date | 2018-08-23 |
United States Patent
Application |
20180238142 |
Kind Code |
A1 |
Hughes; John ; et
al. |
August 23, 2018 |
MULTI-STAGE WELL ISOLATION AND FRACTURING
Abstract
An activation tool is provided for use in a well isolation and
stimulation string, The activation tool has a stationary seat for
receiving a ball deployed down the string, a stationary inner body,
a stationary outer body and a moving sleeve positioned between the
stationary inner and stationary outer bodies and movable from an
open position to a closed position by force of the ball against the
seat.
Inventors: |
Hughes; John; (Calgary,
CA) ; Rasmussen; Ryan D.; (Calgary, CA) ;
Schmidt; James W.; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Resource Completion Systems Inc. |
Calgary |
|
CA |
|
|
Family ID: |
50263165 |
Appl. No.: |
15/960770 |
Filed: |
April 24, 2018 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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14646667 |
May 21, 2015 |
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PCT/CA2013/001074 |
Dec 20, 2013 |
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15960770 |
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61745123 |
Dec 21, 2012 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 34/14 20130101;
E21B 2200/06 20200501; E21B 33/1285 20130101; E21B 33/1216
20130101; E21B 34/103 20130101 |
International
Class: |
E21B 34/10 20060101
E21B034/10; E21B 34/14 20060101 E21B034/14 |
Claims
1. An activation tool for use in a well isolation and stimulation
string, said activation tool comprising: a. a stationary seat for
receiving a ball deployed down the string; b. a stationary inner
body; c. a stationary outer body; and d. an internal sleeve
positioned between the stationary inner and stationary outer bodies
said internal sleeve being shiftable from an open position to a
closed position by force of the ball against the seat, said
internal sleeve further comprising: i. a collet formed with the
internal sleeve and shiftable to lock the moving internal sleeve in
the closed position, wherein the internal sleeve and the collet are
shiftable with a single stroke.
2. The activation tool of claim 1, wherein deployment of the ball
onto the seat prevents circulation of liner fluid through the
activation tool and re-directs fluid into a chamber formed between
the stationary inner body and the moving internal sleeve, said
fluid acting to move the sleeve.
3. The activation tool of claim 2, further comprising one or more
shears screws affixing the stationary inner body to the moving
internal sleeve, said shear screws being shearable at a
predetermined liner fluid accumulated in the tool when the ball
lands on the seat, wherein shearing of said one or more shear
screws allows the internal sleeve to shift to the closed
position.
4. A method of closing an activation tool on a stimulation string,
said method comprising: a. deploying a ball down the stimulation
string to the activation tool; b. receiving the ball on a
stationary seat of the activation tool; c. shifting an internal
sleeve being from an open position to a closed position by force of
the ball against the seat; and d. shifting a collet integrally
connected to the internal sleeve to lock the internal sleeve in the
closed position, wherein the internal sleeve and the collet are
shifted in a single stroke.
Description
FIELD OF INVENTION
[0001] The present invention relates to devices for multi-stage,
horizontal well isolation and fracturing.
BACKGROUND OF THE INVENTION
[0002] An important challenge faced in oil and gas well production
is producing hydrocarbons that are locked into formations and not
readily flowing. In such cases, treatment or stimulation of the
formation is necessary to fracture the formation and provide
passage of hydrocarbons to the wellbore, from which it can be
brought to the surface and produced.
[0003] Fracturing of formations via horizontal wellbores
traditionally involves pumping a stimulant fluid through either a
cased or open hole section of the wellbore and into the formation
to fracture the formation and produce hydrocarbons therefrom.
[0004] In many cases, multiple sections of the formation are
desirably fractured either simultaneously or in stages. Tubular
strings for the fracing of multiple stages of a formation typically
include one or more fracing tools separated by one or more
packers.
[0005] In some circumstances frac systems are deployed in cased
wellbores, in which case perforations are provided in the cemented
in system to allow stimulation fluids to travel through the fracing
tool and the perforated cemented casing to stimulate the formation
beyond. In other cases, fracing is conducted in uncased, open
holes.
[0006] In the case of multistage fracing, multiple frac valve tools
are used in a sequential order to frac sections of the formation,
typically starting at a toe end of the wellbore and moving
progressively towards a heel end of the wellbore.
[0007] Many configurations have been developed in the field to frac
multiple stages of a formation. However, a need still exists for a
fracing system that will ensure stimulation of the formation from a
toe end to a heel end of the wellbore, while being simple in
construction, small in size and effective at fracing formations in
multiple stages
SUMMARY OF THE INVENTION
[0008] An activation tool is provided for use in a well isolation
and stimulation string, said activation tool comprising a
stationary seat for receiving a ball deployed down the string, a
stationary inner body, a stationary outer body and a moving sleeve
positioned between the stationary inner and stationary outer bodies
and movable from an open position to a closed position by force of
the ball against the seat.
[0009] A first stage frac valve tool is also provided for use in a
well stimulation string, said first stage frac valve tool
comprising a stationary outer body and an internal piston movable
between an closed and an open position.
[0010] A singular tool is further provided comprising a float shoe,
an activation tool comprising a stationary seat for receiving a
ball deployed down the string, a stationary inner body, a
stationary outer body and a moving sleeve positioned between the
stationary inner, stationary outer bodies and movable from an open
position to a closed position by force of the ball against the seat
and integrally built with the float shoe and a first stage frac
valve comprising a stationary outer body and an internal piston
movable between an closed and an open position and integrally built
with the activation tool.
[0011] A cased hole packer is further provided comprising an
integral setting tool.
BRIEF DESCRIPTION OF DRAWINGS
[0012] FIG. 1 is a schematic diagram of a horizontal well fitted
with the tools of the present invention;
[0013] FIG. 2 is a cross-sectional view of one example of the
activation tool of the present invention, in various stages of
use;
[0014] FIG. 3 is a cross sectional view of one example of the first
stage frac valve tool of the present invention, in various stages
of use;
[0015] FIG. 4 is a cross sectional view of one example of the cased
hole packer of the present invention,
[0016] FIG. 5 is a cross sectional view of the cased hole packer of
the present invention, showing a first means of deployment;
[0017] FIG. 6 is a cross sectional view of the cased hole packer of
the present invention, showing a collet type latch seal
assembly;
[0018] FIG. 7 is a cross-sectional view of a cased hole packer that
may be deployed on the casing string;
[0019] FIG. 8 is a cross-sectional view of one example of a cased
hole anchor of the present invention; and
[0020] FIG. 9 is a schematic diagram of dual horizontal liners
drilled in one well.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0021] A series of tools is provided that improve on existing
horizontal isolating and fracing tools, by providing increased
safety during installation, reduced rig time and greater
dependability of deploying the tools to the end of the horizontal
section of the wellbore.
[0022] By combining both a slim outside diameter and short length,
the present tools eliminate the need for handling pup joints,
thereby reducing the rigidity of the liner. These features permit
the more flexible, reduced outside diameter tool string to be
deployed into the wellbore with greater ease.
[0023] The present invention consists of a series of tools
strategically located along a liner and deployed into the open hole
section of the wellbore. The tools provide a means of isolating
various stages of the horizontal wellbore. After isolating various
stages, stimulation fluid can be pumped from surface and through
valve tools that are opened sequentially to thereby multi-stage
frac the formation.
[0024] With reference to FIG. 1, in a preferred method of
deployment, the present system of tools comprises a cased hole
packer 500 that anchors the liner and forms a seal between the
casing string and the open hole. A float shoe or guide 50 is run at
the toe of the liner. An activation tool 100 is placed a
pre-determined distance from the guide shoe 50. Next is a first
stage frac valve tool 200, and then an series comprising an open
hole packer 300 alternated with one or more subsequent stage frac
valve tools 400. It would be well understood by a person of skill
in the art that FIG. 1 merely represents one example of a tubular
fracing string of tools and that additions, omissions and
alterations to the illustrated string and its components can be
made without departing from the scope of the present invention.
[0025] The float shoe 50 is preferably provided with an open end
having a flap covering. The open end allows the liner pressure to
be at least somewhat equalized with the formation pressure while
the flap prevents ingress of formation fluids into the liner.
[0026] It would be understood by a person of skill in the art that
any float shoe or similar device known in the art could be used
with the tools of the present invention without departing from the
scope thereof.
[0027] The activation tool 100, as seen in FIG. 2 comprises an
opening 102. The one piece construction of the outer body 120 of
the activation tool allows torque to be applied from the upper
liner section, through the tool and into the liner to make up the
liner string. The activation tool 100 can be lifted by hand and
hand threaded onto the liner, which is typically gripped at the rig
floor, and then a section of upper liner, typically gripped in an
elevator or similar device, can be lowered onto the tool.
[0028] The opening 102 is open during deployment such that fluid
can be circulated through the opening 102 when the liner is being
run into the well, as seen in FIG. 2a. At a predetermined depth, a
ball 104 is circulated down to the activation tool 100, as seen in
FIG. 2b, and prevents circulation through opening 102 and
re-directs fluid into a chamber 106 formed between an activation
tool inner body 118 and a sleeve 110. The sleeve 110 comprises a
first and a second diameter, D1 and D2 respectively. While D1 is
exposed to wellbore fluids and experiences wellbore pressures, D2
is exposed to fluid pressure from within the liner. The product of
the difference in these pressures and the difference in these
diameters defines the force needed to displace sleeve 110 and move
the activation tool 200 from an open (FIGS. 2a, 2b) to a closed
position (FIG. 2c).
[0029] Pressure from the liner fluid serves to shears screws 108
that have been holding the sleeve 110 in the open position. The
sleeve 110 then shifts and the opening 102 closes, blocking flow
through the opening 102. With fluid flow blocked in the liner,
pressure increases to thereby trigger activation and setting of the
open hole packers 300 and the cased hole packer 500.
[0030] A number of seals 116 between the sleeve 110 and the
activation tool inner body 118 guide this movement from open to
closed.
[0031] Preferably, a collet 112 located on the sleeve 110 catches
against an end of the activation tool inner body 118 when the
sleeve 110 is in the closed position and prevents the sleeve 110
from shifting back to its original, open position. In its locked
and set position, the activation tool 100 further advantageously
serves as a redundant safety device to the float shoe 50, ensuring
that wellbore fluids do not enter the liner prior to fracing.
[0032] Advantageously, the opening 102 in the activation tool has
been designed with minimum moving parts. The ball 104 and its
corresponding seat 114 are entirely comprised of non-moving
components, thereby eliminating the risk of creating a hydraulic
lock, or locking of parts due to the presence of an incompressible
fluid that has nowhere to be displaced to, below the opening 102.
Instead, the internal sleeve 110 shifts to close the opening 102
and is locked by means of the collet 112, so that in the event that
the ball 104 undesirably rolls off of the valve seat 114, the
opening 102 remains in the closed position.
[0033] The next tool in the present invention is the first stage
frac valve tool 200, depicted in FIGS. 3a and 3b. This is the frac
valve through which the first stage of the stimulation is pumped to
the toe of the wellbore. The present first stage frac valve tool
200 can be lifted by hand and hand threaded onto the liner, which
is typically gripped at the rig floor, and then a section of upper
liner, typically gripped in an elevator or similar device, can be
lowered onto the tool.
[0034] Since the closing of the activation tool 100 prevents
circulation of fluid, the first stage frac valve tool 200 relies
solely on applied pressure to open. The opening pressure of the
first stage frac valve tool 200 must be greater than the pack off
pressure required to set the open hole packer 300 and cased hole
packer 500. Increasing liner fluid pressure acts on surface D1 to
apply pressure on piston 204. The opening pressure of the first
stage frac valve tool 200 is preferably controlled by the number of
shear screws 202 installed into the piston 204, although other
known means of controlling opening pressure would also be
understood by a person of skill in the art and encompassed by the
present invention. At a pre-determined shear force, the shear
screws 202 shear allowing the piston 204 to be shifted to the open
position, as seen in FIG. 3b.
[0035] A pair of seals 206 between the piston 204 and the frac
valve outer body 222 guide movement of the pistion 204 from closed
to open. In the open position, ports 210 are opened to allow fluid
to flow from inside the liner into the formation to thereby
stimulate the adjacent formation.
[0036] A snap ring 208 preferably locks the piston 204 in the open
position, although other known biasing means may also be used and
would be well known to a person skilled in the art. Advantageously,
the moving parts of the first stage frac valve tool 200 are all
internal, meaning they do not have to overcome friction against the
wellbore to shift from closed to open, allowing better control over
the system.
[0037] A further advantage of the present first stage frac valve
tool 200 is its ability to transmit torque. During installation
torque can be transmitted through the first stage frac valve tool
200 from a joint above into the liner below in order to make up the
threads. The internal body connection of the first stage frac valve
tool 200 has been designed to handle torque greater than the
make-up torque of the liner connections. The ability to transmit
torque, combined with its short size, eliminate the need for
handling joints that would need to be torqued on both ends of the
first stage frac valve tool 200.
[0038] Preferably, the geometry of the fracture ports 210 provides
easy identification for the first stage frac valve tool 200,
thereby reducing the potential for incorrect placement in the liner
string. The unique geometry of the fracture ports 210
differentiates the appearance of the first stage frac valve tool
200 from other similar looking valves installed on the liner. Ports
210 may also preferably be sized to reduce or prevent ingress of
wellbore debris into the liner.
[0039] In a further preferred embodiment of the present invention a
singular tool (not shown) comprising a float shoe 50/activation
tool 100/first stage frac valve tool 200 can be used to replace
individual float shoe 50, activation tool 100 and first stage frac
valve tool 200 with liner joints connecting them. Advantageously,
the singular combination tool (not shown) requires less threaded
connections, thereby reducing potential leak paths and decreases
rig time since only one threaded connection needs to be torqued on
the rig floor. The singular combination tool (not shown) also
ensures that the fracture ports 210 of the first stage frac tool
200 are as close to the toe of the well as possible.
[0040] When the first stage frac valve tool 200 opens, the
formation is immediately exposed to high pressure liner fluid. In
an alternative embodiment, the first stage frac valve tool 200 may
be configured such that a high fluid pressure is required to unlock
the piston 204, then a second surge of low pressure serves to open
the fracture ports 210. This embodiment of the first stage frac
valve tool 100 can be used to protect sensitive formations from
excessive pressures.
[0041] The next tools installed onto the liner are a series of one
or more open hole packers 300 and a frac valve tools 400. The open
hole packers 300 are preferably single element open hole packers
300.
[0042] The next element of the present invention is the cased hole
packer 500, which is run at the top of the liner, and is
illustrated in FIG. 4. The cased hole packer 500 is a hydraulically
set, preferably permanent packer with a tie back receptacle 502 and
is used to anchor the liner into the casing string and provide a
seal between the top of the liner and the casing string.
[0043] Many prior art cased hole packers require a setting tool
that is separate to the cased hole packer and used to set the
packer against the casing string. To accommodate such cased hold
packer and setting tool, the tool must be run on drill pipe, which
is narrower than a typical frac string and therefore provides
sufficient room between the drill pipe outer diameter (OD) and the
casing string to accommodate the setting tool. Once deployed, the
setting tool and drill pipe are then typically pulled out and a
frac string is deployed to proceed with the fracing operating.
[0044] The present cased hole packer 500 advantageously
incorporates an integral setting tool in the form of slips 504 to
activate the cased hole packer 500. The slips 504 do not extend
beyond the OD of the cased hole packer 500 and require no
additional space. Thus the present cased hole packer 500 and other
present tools can be run on a frac string, without the need to run
a drill string and then change out to a frac string, saving time
during operation. It would be well understood by a person of skill
in the art that the present cased hole packer 500 can also be
deployed on drill string and any number of means can be used to
accommodate this smaller diameter pipe.
[0045] The opposing slips 504 serve to anchor the cased hole packer
500 to the casing string in both tension and compression due to
wickers formed on an outer surface thereof that act to engage the
casing string inside diameter when the cased hole packer 500 is
set.
[0046] After the liner has been deployed, the cased hole packer 500
is set by pressure buildup in the liner due to activation of the
activation tool 100. A setting piston 534 on the cased hole packer
mandrel 530 comprises a first and a second diameter, D1 and D2
respectively. While D1 is exposed to wellbore fluids and
experiences wellbore pressures, D2 is exposed to fluid pressure
from within the liner. The product of the difference in these
pressures and the difference in these diameters defines the force
needed to displace setting piston 534 and move the cased hole
packer 500 from an unset to a set position. A pair of seals 516
between the setting piston 534 and the mandrel body 530 guide this
movement from unset to set. Upon movement of the setting piston 534
triggers movement of the opposing slips 504 against a pair of upper
and lower cones 520, that in turn presses against the packing
element 522 causing packing element 522 to protrude into the
wellbore until it comes in to sealing contact with the casing
string inside diameter (ID). The cased hole packer 500 is held in
place and prevented from unsetting by a ratchet ring 528.
[0047] The packing element 522 is comprised of a solid band of
flexible material having a thickness such that an outer surface of
the packing element 522 in its unset position sits flush with an
outer surface of the upper and lower cones 520. Suitable materials
for the packing element include any number of fluorocarbons and
per-flourocarbons such as AFLAS.TM., HNBR, and Viton.TM., although
it would be understood by a person of skill in the art that any
flexible material showing resiliency and sufficient strength to
maintain packing against wellbore fluid pressure would be suitable
for the purposes of the present invention.
[0048] In a preferred embodiment, the packing element 522 is
thinner at its axial midpoint than everywhere else. More
preferably, the packing element 522 is formed with a
circumferential groove 540 of predetermined width and depth around
its inner surface at the axial midpoint, such groove 540 creating a
thinner middle portion of the packing element 522. The groove 540
ensures that the packing element 522 protrudes from its axial
midpoint, thereby providing even contact with the wellbore and a
positive seal. In a further preferred embodiment, a packing element
ring 542 is provided on the mandrel 530 onto which the packing
element groove 540 sits. The packing element ring 542 fills in the
void of the groove 540 and ensures that the midpoint of the packing
element 522 protrudes outwards upon actuation, and does not fold
inwardly into itself.
One or more anti-extrusion expandable rings 524 hold the packing
element 522 in place and press against the packing element 522 in
actuation.
[0049] More preferably, the anti-extrusion rings 524 are positioned
between backup rings 544 and the upper and lower cones 520
respectively.
[0050] The backup rings 544 are preferably shaped to allow an end
of the upper and lower cones 520 to travel along and wedge into one
contour of the backup ring 544 while allowing the anti-extrusion
ring 524 to travel along and wedge between the upper and lower
cones 520 and another contour of the backup ring 544 at each end of
the packing element 522. Such wedging prevents the packing element
522 from extruding internally and prevents packing element creep
during high differential pressures and helps centralize the cased
hole packer 500 while setting.
[0051] The use of the present anti-extrusion rings 524 creates a
barrier around the packing element 522 after the cased hole packer
500 is set. Without this barrier the packing element 522 would not
be able to maintain a seal at high differential pressures inside
the casing.
[0052] A ratchet ring 528 is located between the mandrel body 530
and the setting piston 534 that serves to prevent the piston 534
from backing off from a set position, thus ensure that the packing
element 522 remains in a set position once set.
[0053] In the present cased hole packer 500 the ratchet ring 528 is
preferably comprised of a split ring with an inner surface ratchet
profile and an outer surface ratchet profile. Preferably the inner
surface ratchet profile is finer than the outer surface ratchet
profile.
[0054] The ratchet ring 528 is first assembled onto the mandrel 530
of the cased hole packer 500, at least a part of the outer surface
of the mandrel 530 having a ratchet profile that mates with the
inner surface ratchet profile of the ratchet ring 528. Preferably
the ratchet ring 528 is assembled over one or more spring pins 546
installed on the mandrel 530 to maintain the position and alignment
of the ratchet ring 528. A locking body thread 532 formed on an
inner surface of at least part of the setting piston 534 is then
installed over the ratchet ring 528. Preferably, the locking body
thread 532 mates with the outer surface ratchet profile of the
ratchet ring 528.
[0055] Orientation of the inner surface ratchet profiles of the
ratchet ring 528 allow the setting piston 534 and ratchet ring 528
to travel from unset to set position along the mandrel body 530,
while preventing the setting piston 534 and ratchet ring 528 from
sliding back to an unset direction from a set position. Orientation
of the outer surface ratchet profile of the ratchet ring 528 allows
the setting piston 534 to slide over the outer surface of the
ratchet ring 528 when it is being installed onto the ratchet ring
528. Once the locking body thread 532 and the outer surface ratchet
profile of the ratchet ring 528 mate, these mating profiles lock
the ratchet ring 528 to the setting piston 534 when the setting
piston 534 moves from an unset to a set position.
[0056] The ratchet ring 528 and setting piston 534 have a larger ID
than the mandrel body 530 OD, thereby being able to be installed on
the mandrel 530 without having to split the locking body 532 from
the setting piston 534.
[0057] The tie back receptacle 502, illustrated in more detail in
FIG. 5, acts as a sealing interface and latching mechanism between
the liner and drill string, should a drill string be used in
deployment, and as a sealing interface and latching mechanism
between the liner and frac string during stimulation.
[0058] In a preferred embodiment, the cased hole packer 500 may
also comprise one or more grooves (not shown) machined
circumferentially around the O.D. of the cased hole packer 500. The
grooves can receive a clamp to permit shop pressure testing of the
cased hole packer 500 to high pressures to verify correct assembly.
The clamp prohibits the cased hole packer 500 from setting, while
testing the integrity of the tool's internal seals.
[0059] The present cased hole packer can be deployed using three
different deployment methods. In a first embodiment, the cased hole
packer 500 can be attached to a jay type latch seal assembly 506,
illustrated in FIG. 5. The latch seal assembly 506 is used to
connect and seal the liner to the drill string, if a drill string
is used, during deployment. The latch seal assembly 506 will have
an upper thread 508 compatible with the thread on the drill string.
It also has an anchoring mechanism 510 compatible with the tie back
receptacle 502 that serves to anchor it to the packer. Seals 512
located on the latch seal assembly 506 engage matching seal bore
located on the tie back receptacle 502 to prevent fluid leak
between the tie back receptacle 502 and the latch seal assembly
506. In a situation where the latch seal assembly 506 used directly
with the frac string, and where no drill string need first be
deployed, an upper thread 508 is sized to be compatible with the
threads on the frac string.
[0060] The jay type latch seal assembly 506 is preferably full bore
with an ID matching the liner I.D., and no restrictions in the
mandrel 514 of the latch seal assembly 506. Shear screws 518
installed prior to deployment ensure that the liner and cased hole
packer 500 cannot disengage from the drill/frac string prematurely.
The shear screws 518 are installed through the tie back receptacle
502 and engage a profile machined on the outer surface of the jay
type latch seal assembly 506. Torque is required to break these
shear screws 518. Although the current design of the jay type latch
seal assembly is illustrated as having an anchoring mechanism in
the form of three jay pins, it could instead have two or more jay
pins, and such embodiments are encompassed by the scope of the
present invention. Preferably the seals 512 are bonded seals,
although other seal configurations could be used instead, including
polypak type seals, o-rings or v-seals. The seal design on the
latch seal assembly 506 allows the latch to be removed under
differential pressure, thus eliminating seal damage.
A second deployment method that can be used with the cased hole
packer 500 is depicted in FIG. 6, which uses a collet type latch
536, to deploy the liner and frac string. The collet type latch
seal assembly 536 has flexible fingers that can deflect and allow
the seal assembly to be stabbed into the receptacle. The flexible
collet latch 536 can preferably comprise a tread profile machined
on its external surface that matches a similar thread profile
machined on the I.D. of the receptacle. The collet type latch seal
assembly 536 can preferably be removed from the receptacle by
rotating the work string clockwise while picking up, which serves
to screw the collet type latch 536 out of the receptacle.
[0061] A third deployment method that can be used with the cased
hole packer 500 is depicted in FIG. 7, in the form of a casing
string 538 screwed directly into top of cased hole packer 500. In
this case, the casing string is used for both deployment and
fracturing and the casing string is not retrieved when the process
is complete.
[0062] In one example of operation of the tools of the present
invention, a liner is assembled with the following components, as
illustrated in FIG. 1: a float shoe 50, the present activation tool
100, a liner, the present first stage frac valve tool 200, and then
a series comprising a liner, an open hole packer 300, a liner and a
frac valve 400. Optionally, an open hole anchor 600 may be used
between the activation tool 100 and the first stage frac valve tool
200 to anchor the liner to the wellbore. Alternative to an open
hole anchor 600 centralizers, stabilizers or other suitable means
known in the art may also be used for this purpose.
[0063] Preferably up to 40 frac valves 400, on a 41/2'' liner for
example, separated with open hole packer 300s can be used in a
string. A cased hole packer 500 is attached to the upper end of the
casing. A latch seal assembly 506, collet type latch 536 or other
known means can be used to attach the cased hole packer 500 to the
casing.
[0064] The liner is run into the conditioned bore hole by a drill
string or on a frac string. At a predetermined depth, ball 104 is
circulated down to the activation tool 100 to stop fluid flow.
Pressure increase, thereby setting both the cased hole packer 500
and the open hole packers 300. A pressure test may optionally be
performed inside the casing to determine if the cased hole packer
500 has set properly. If the liner was run on a drill string, the
latch seal assembly 506, collet type latch 536 or other connection
means can next be removed from the cased hole packer 500 and the
drill string and connecting means are removed from the well and a
frac string and associated connecting means are deployed.
Otherwise, if the liner was run downhole on a frac string, no
replacement has to be made.
[0065] Further pressure is applied to the frac string. At a
pre-determined setting pressure that is higher than the pack off
pressure of the open hole packers 300 and cased hole packer 500,
the first stage frac valve tool 200 shifts to the open position and
stimulation fluid is pumped into the formation to stimulate the
formation from the toe of the wellbore to the first stage frac
valve tool 200. Proppant is then pumped into the fracture. Next
subsequent frac valve tools 400, starting with that closest to the
first stage frac valve tool 200, are activated to thereby open
communication between the inside of the liner and the isolated
section of the formation between the two open hole packer 300
straddling the particular frac valve 400.
[0066] The stimulation fluid pumped through the ports of the frac
valve 400 fractures the exposed formation between the open hole
packers 300 used to isolate that stage. Whenever this stage has
been fractured, a next frac valve 400 is activated and the process
is repeated. The process can be repeated up to 40 times in total in
a 41/2'' liner, for example. Other sizes of liners can have a
different number of frac valve tools 400 and open hole packers 300.
When all the desired stages have been fractured, the well is
allowed to flow and formation pressure from formation fluid flow
acts to deactivate the frac valves 400 and allows formation fluid
flow into the liner. Afterwards the frac string and connecting
means can be removed from the well.
[0067] In the case of ball drop activated frac valve tools 400, if
desired, the seats of the frac valves 400 can be drilled out at a
later date.
[0068] In the event the operator needs to set the liner in an open
hole, an open hole anchor 600, illustrated in FIG. 8 can replace
the cased hole packer 500. This scenario can exist whenever dual
horizontals are drilled in one well, as seen in FIG. 9. The
hydraulic set open hole anchor 600 is full bore. It is run in
conjunction with an open hole packer 300 and tie back receptacle
(not shown) to act as a means to seal and anchor the liner in the
open hole. The tieback receptacle provides a means to deploy the
liner then act as a means to seal and anchor the fracture string to
the liner.
The open hole anchor 600 is preferably full bore with no mandrel
restrictions and has the same I.D. as the liner. Preferably it is
operated with slips 602 to anchor the liner to the formation. More
preferably the open hole anchor 600 employs a similar setting
piston and ratchet configurations of the cased hole packer 500.
[0069] Preferably, after the bore hole has been drilled and before
the liner is installed, a reamer trip is performed. The present
reamer has a unique design to mimic the geometry of the stiffest
components on the liner string. The present reamer has one set of
blades instead of multiple sets and its reduced O.D. and short
length enable it to be deployed and retrieved quickly while still
ensuring the bore hole has no obstructions to impede running the
liner with the present suite of fracturing tools. The reamer
preferably has a small O.D. and a short length to mimic the
geometry of the present tools of the frac string illustrated in
FIG. 1. The geometry of the reamer permit ease of deployment and in
some circumstances allows the reamer to trave to the toe end of the
frac string without needing to ream any tight spots in the
wellbore. This reduces rig time while ensuring that the present
frac tools can be deployed into the wellbore.
[0070] In the foregoing specification, the invention has been
described with specific embodiments thereof; however, it will be
evident that various modifications and changes may be made thereto
without departing from the broader spirit and scope of the
invention.
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