U.S. patent application number 14/997639 was filed with the patent office on 2016-07-28 for method and apparatus for well completion.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Rodrigo Aviles Miranda, Harold Landmark Henriksen, Derek Ingraham.
Application Number | 20160215581 14/997639 |
Document ID | / |
Family ID | 56433212 |
Filed Date | 2016-07-28 |
United States Patent
Application |
20160215581 |
Kind Code |
A1 |
Ingraham; Derek ; et
al. |
July 28, 2016 |
METHOD AND APPARATUS FOR WELL COMPLETION
Abstract
Disclosed is a method and apparatus for performing a well
completion. The apparatus comprises a tool string slidably
locatable within the well and a shifting tool slidably locatable
within the sleeve at an end of a tool string the shifting tool
having a central bore therethrough and keys operable to be extended
from an outer surface of the shifting tool when the central bore is
supplied with the fluid above a predetermined pressure, the keys
being engagable upon the sleeve so as to permit the shifting tool
to move the sleeve longitudinally within the tubular body. The
apparatus further comprises a motor located at a distal end of the
tool string having a mill operably rotated thereby and means for
selectably actuating one of the shifting tool or motor. The method
comprises locating the tool string into the well and providing a
fluid flow rate through the tool string to the first fluid flow
range to actuate the shifting tool. The method further comprises
increasing the fluid flow rate above the first fluid flow range to
deactivate the shifting tool and increasing the fluid flow rate
above the first fluid flow range and a predetermined fluid flow
rate to activate the motor.
Inventors: |
Ingraham; Derek;
(Peterculter, GB) ; Henriksen; Harold Landmark;
(Missouri City, TX) ; Aviles Miranda; Rodrigo;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
56433212 |
Appl. No.: |
14/997639 |
Filed: |
January 18, 2016 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
62106574 |
Jan 22, 2015 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 29/002 20130101; E21B 2200/06 20200501; E21B 34/14
20130101 |
International
Class: |
E21B 29/00 20060101
E21B029/00; E21B 43/26 20060101 E21B043/26; E21B 43/267 20060101
E21B043/267; E21B 34/10 20060101 E21B034/10 |
Claims
1. An apparatus for performing a well completion comprising: a tool
string slidably locatable within said well; shifting tool slidably
locatable within said sleeve at an end of a tool string said
shifting tool having a central bore therethrough and keys operable
to be extended from an outer surface of said shifting tool when
said central bore is supplied with said fluid above a predetermined
pressure, said keys being engagable upon said sleeve so as to
permit said shifting tool to move said sleeve longitudinally within
said tubular body; a motor located at a distal end of said tool
string having a mill operably rotated thereby; and means for
selectably actuating one of said shifting tool or motor.
2. The apparatus of claim 1 wherein said means for selectably
actuating one of said shifting tool or motor is operable to actuate
said motor between a first fluid flow range through said tool
string.
3. The apparatus of claim 2 wherein said means for selectably
actuating one of said shifting tool or motor is operable to actuate
said shifting tool above a predetermined fluid flow rate.
4. The apparatus of claim 3 wherein said predetermined fluid flow
rate is higher than said first fluid flow range.
5. The apparatus of claim 1 wherein the first fluid flow range is
from from 60 galUS/min to 119 galUS/min.
6. The apparatus of claim 2 wherein the predermined fluid flow rate
is between 120 galUS/min and 160 galUS/min.
7. The apparatus of claim 1 wherein a circulation device is located
between the shifting tool and motor.
8. The apparatus of claim 7 wherein the circulating device is
resettable.
9. A method for performing a well completion comprising: locating a
tool string into a well having a shifting tool and a motor operably
rotating a mill at distal end thereof; providing a fluid flow rate
through said tool string to a first fluid flow range to actuate
said motor; increasing said fluid flow rate above said first fluid
flow range to deactivate said motor; and increasing said fluid flow
rate above said first fluid flow range and a predetermined fluid
flow rate to activate said shifting tool.
10. The method of claim 9 wherein the first fluid flow range is
from from 60 galUS/min to 119 galUS/min.
11. The method of claim 9 wherein the predermined fluid flow rate
is between 120 galUS/min and 160 galUS/min.
12. A method for hydraulically fracturing a well comprising:
locating a tool string, mounted with sliding sleeves, into a well
having a shifting tool and a motor operably rotating a mill at
distal end thereof; providing a fluid flow rate through said tool
string to a first fluid flow range to actuate said motor;
increasing said fluid flow rate above said first fluid flow range
to deactivate said motor; increasing said fluid flow rate above
said first fluid flow range and a predetermined fluid flow rate to
activate said shifting tool; opening a sliding sleeve using the
shifting tool; and pumping a fluid above the fracturing pressure of
the formation.
13. The method of claim 12 wherein the hydraulic fracturing is a
pin-point fracturing.
14. The method of claim 12 wherein the fluid contains proppant.
15. The method of claim 12 wherein the first fluid flow range is
from from 60 galUS/min to 119 galUS/min.
16. The method of claim 12 wherein the predermined fluid flow rate
is between 120 galUS/min and 160 galUS/min.
17. The method of claim 12 further comprising closing the sleeve
after the formation has been hydraulically fractured.
18. The method of claim 17 further comprising hydraulically
fracturing at least a further zone.
19. The method of claim 12 wherein no sealing element is present on
the tool string during the hydraulic fracturing operations.
Description
BACKGROUND
Field
[0001] The present disclosure relates to well completion in general
and in particular to a method and apparatus for operating a high
pressure shifting tool within a well.
Description of Related Art
[0002] Hydrocarbon fluids such as oil and natural gas are obtained
from a subterranean geologic formation, referred to as a reservoir,
by drilling a well that penetrates the hydrocarbon-bearing
formation. Once a wellbore is drilled, various forms of well
completion components may be installed in order to control and
enhance the efficiency of producing the various fluids from the
reservoir.
[0003] Fracturing is used to increase permeability of subterranean
formations. A fracturing fluid is injected into the wellbore
passing through the subterranean formation. A propping agent
(proppant) is injected into the fracture to prevent fracture
closing and, thereby, to provide improved extraction of extractive
fluids, such as oil, gas or water.
[0004] One difficulty that may be encountered in some fracturing
operations is that there me debris located within the wellbore
which impedes the movement of the equipment necessary for the
fracturing operation. In such situations it may be conventionally
necessary to remove the fracturing equipment from the hole and
introduce a drill thereinto to clear the debris whereafter the
fracturing operations may continue.
[0005] Improvements in completing these unconventional formations
would be welcome by the industry.
SUMMARY
[0006] In embodiments the disclosure pertains to methods for
completing a well comprising completing at least a zone of a first
well using a pin-point fracturing technique without using a sealing
element.
[0007] In embodiments, the disclosure relates to methods for
completing a well comprising cleaning out the wellbore and then
fracturing the well without having the tool coming out of the
well.
[0008] In embodiments, the disclosure aims at completions tools
combining cleaning tool and fracturing tool on a same
toolstring.
[0009] According to a further embodiment, there is disclosed an
apparatus for performing a well completion comprising a tool string
slidably locatable within the well and a shifting tool slidably
locatable within the sleeve at an end of a tool string the shifting
tool having a central bore therethrough and keys operable to be
extended from an outer surface of the shifting tool when the
central bore is supplied with the fluid above a predetermined
pressure, the keys being engagable upon the sleeve so as to permit
the shifting tool to move the sleeve longitudinally within the
tubular body. The apparatus further comprises a motor located at a
distal end of the tool string having a mill operably rotated
thereby and means for selectably actuating one of the shifting tool
or motor.
[0010] The means for selectably actuating one of the shifting tool
or motor may be operable to actuate the shifting tool between a
first fluid flow range through the tool string. The means for
selectably actuating one of the shifting tool or motor may be
operable to actuate the shifting tool above a predetermined fluid
flow rate. The predetermined fluid flow rate may be higher than the
first fluid flow range.
[0011] According to a further embodiment, there is disclosed a
method for performing a well completion comprising locating a tool
string into a well having a shifting tool and a motor operably
rotating a mill at distal end thereof and providing a fluid flow
rate through the tool string to a first fluid flow range to actuate
the motor. The method further comprises increasing the fluid flow
rate above the first fluid flow range to deactivate the motor and
increasing the fluid flow rate above the first fluid flow range and
a predetermined fluid flow rate to activate the shifting tool.
BRIEF DESCRIPTION OF THE DRAWINGS:
[0012] Certain embodiments of the disclosure will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements. It should be understood,
however, that the accompanying drawings illustrate only the various
implementations described herein and are not meant to limit the
scope of various technologies described herein. The drawings show
and describe various embodiments of the current disclosure.
[0013] FIG. 1 is a cross-sectional view of a wellbore having a
plurality of flow control valves according to a first embodiment of
the present disclosure located therealong.
[0014] FIG. 2 is a cross sectional view of a control valves of for
use in the system of FIG. 1.
[0015] FIG. 3 is a longitudinal cross-sectional view of the control
valve of FIG. 2 as taken along the line 3-3.
[0016] FIG. 4 is a detailed cross-sectional view of the extendable
ports of the valve of FIG. 2 in a first or retracted position.
[0017] FIG. 5 is a detailed cross-sectional view of the extendable
ports of the valve of FIG. 2 in a second or extended position with
the sleeve valve in an open position.
[0018] FIG. 6 is a cross sectional view of the valve of FIG. 2 as
taken along the line 3-3 showing a shifting tool located
therein.
[0019] FIG. 7 is an axial cross-sectional view of the shifting tool
of FIG. 6 as taken along the line 7-7.
[0020] FIG. 8 a lengthwise cross sectional view of the shifting
tool of FIG. 6 taken along the line 8-8 in FIG. 7 with a control
valve located therein according to one embodiment with the sleeve
engaging members located at a first or retracted position.
[0021] FIG. 9 is a cross sectional view of the shifting tool of
FIG. 6 taken along the line 8-8 with a control valve located
therein according to one embodiment with the sleeve engaging
members located at a second or extended position
[0022] FIG. 10 is a perspective view of a shifting tool according
to a further embodiment.
[0023] FIG. 11 exemplifies a possible bottom hole assembly
envisaged by the present disclosure.
DETAILED DESCRIPTION:
[0024] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary and this detailed description, it should be understood that
a concentration range listed or described as being useful,
suitable, or the like, is intended that any and every concentration
within the range, including the end points, is to be considered as
having been stated. For example, "a range of from 1 to 10" is to be
read as indicating each and every possible number along the
continuum between about 1 and about 10. Thus, even if specific data
points within the range, or even no data points within the range,
are explicitly identified or refer to only a few specific, it is to
be understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possessed knowledge of the entire
range and all points within the range.
[0025] The statements made herein merely provide information
related to the present disclosure and may not constitute prior art,
and may describe some embodiments illustrating the disclosure.
[0026] In the specification and appended claims: the terms
"connect", "connection", "connected", "in connection with", and
"connecting" are used to mean "in direct connection with" or "in
connection with via one or more elements"; and the term "set" is
used to mean "one element" or "more than one element". Further, the
terms "couple", "coupling", "coupled", "coupled together", and
"coupled with" are used to mean "directly coupled together" or
"coupled together via one or more elements". As used herein, the
terms "up" and "down", "upper" and "lower", "upwardly" and
downwardly", "upstream" and "downstream"; "above" and "below"; and
other like terms indicating relative positions above or below a
given point or element are used in this description to more clearly
describe some embodiments of the disclosure.
[0027] The disclosure pertains to methods of treating an
underground formation penetrated by either vertical wells or wells
having a substantially horizontal section. Horizontal well in the
present context may be interpreted as including a substantially
horizontal portion, which may be cased or completed open hole,
wherein the fracture is transversely or longitudinally oriented and
thus generally vertical or sloped with respect to horizontal. The
following disclosure will be described using horizontal well but
the methodology is equally applicable to vertical wells.
[0028] The industry has privileged, when it comes to hydraulic
fracturing, what is known as being "plug-and-perf" technique.
Horizontal wells may extend hundreds of meters away from the
vertical section of the wellbore. Most of the horizontal section of
the well passes through the producing formation and are completed
in stages. The wellbore begins to deviate from vertical at the
kickoff point, the beginning of the horizontal section is the heel
and the farthest extremity of the well is the toe. Engineers
perform the first perforating operation at the toe, followed by a
fracturing treatment. Engineers then place a plug in the well that
hydraulically isolates the newly fractured rock from the rest of
the well. A section adjacent to the plug undergoes perforation,
followed by another fracturing treatment. This sequence is repeated
many times until the horizontal section is stimulated from the toe
back to the heel. Finally, a milling operation removes the plugs
from the well and production commences.
[0029] The common practice in the art is to perforate 4-6 clusters,
and push a slickwater laden fluid at or above fracture pressure to
create fractures; it is estimated that 30 to 60% of these
perforations do not produce due to for example screen out,
geological constraint, etc., and thus for every 100 perforations in
a wellbore, commonly only 30 to 70 of the conventional perforations
are useful for production.
[0030] To respond to that, some operations now involve what is
known as pin-point fracturing, which may be defined as the
operation of pumping a fluid above the fracturing pressure of the
formation to be treated through a single entry. The entry may be a
perforation, a valve, a sleeve, or a sliding sleeve. Generally,
sliding sleeves in the closed position are fitted to the production
liner. The production liner is placed in a hydrocarbon formation.
An object is introduced into the wellbore from surface, and the
object is transported to the target zone by the flow field or
mechanically, for example using a wireline or a coiled tubing. When
at the target location, the object is caught by the sliding sleeve
and shifts the sleeve to the open position, alternatively the
object is catching the sleeve and opens it. A sealing device, such
as a packer or cups, is positioned below the sleeve to be treated
in order to isolate the lower portion of the wellbore. The sealing
device is set, fluid is pumped into the fracture and then the
sealing device is unset and moved below the next zone (or sleeve)
to be treated. Representative examples of sleeve-based systems are
disclosed in U.S. Pat. No. 7,387,165, U.S. Pat. No. 7,322,417, U.S.
Pat. No. 7,377,321, US 2007/0107908, US2007/0044958,
US2010/0209288, U.S. Pat. No. 7,387,165, US2009/0084553, U.S. Pat.
No. 7,108,067, U.S. Pat. No. 7,431,091, U.S. Pat. No. 7,543,634,
U.S. Pat. No. 7,134,505, U.S. Pat. No. 7,021,384, U.S. Pat. No.
7,353,878, U.S. Pat. No. 7,267,172, U.S. Pat. No. 7,681,645, U.S.
Pat. No. 7,066,265, U.S. Pat. No. 7,168,494, U.S. Pat. No.
7,353,879, U.S. Pat. No. 7,093,664, and U.S. Pat. No. 7,210,533,
which are hereby incorporated herein by reference. A fracturing
treatment is then circulated down the wellbore to the formation
adjacent the open sleeve.
[0031] Operations involving sliding sleeve imply to have a casing
or liner that having pre-fitted or preinstalled sleeves when the
well is cased thereby prior to cementing the well. Operators then
typically need to clean the well in order to start the hydraulic
stimulation; this is known in the industry as a clean out run which
involves cleaning potential debris that may remain in the wellbore
and usually takes hours before the fracturing tools can be lowered
down the well. The present disclosure aims at optimizing such clean
out by enabling to combine both the clean out run with the trip to
lower the hydraulic stimulation tools.
[0032] Embodiments herein relate to methods of completing an
underground formation using multi-stage pin-point fracturing for
treating a well without using any sealing element.
[0033] In embodiments, a cased-hole is provided with a production
tubing (or casing) fitted with sliding reclosable sleeves (as in
FIG. 1) at the desired location and quantity. After the completion
(desired amount of sleeves and casing) is installed into the well,
the well would be set up for fracture/stimulation operations.
Using, for example, a coil tubing or stick pipe an actuation device
would be conveyed into the well.
[0034] The actuation device, indifferently mentioned here as
shifting tool, may be a tool that is equipped with a sleeve
engaging member selectably extendable from the shifting tool in
parallel to a central axis of the shifting tool and engagable upon
the sleeve wherein the shifting tool is moveable so as to cause the
sleeve to selectably cover and uncover the apertures. A suitable
combination sliding sleeve and shifting tool may be found in
US2012/0125627 incorporated herein by reference in its
entirety.
[0035] Referring to FIG. 1, a wellbore 10 is drilled into the
ground 8 to a production zone 6 by known methods. The production
zone 6 may contain a horizontally extending hydrocarbon bearing
rock formation or may span a plurality of hydrocarbon bearing rock
formations such that the wellbore 10 has a path designed to cross
or intersect each formation. As illustrated in FIG. 1, the wellbore
includes a vertical section 12 having a valve assembly or Christmas
tree 14 at a top end thereof and a bottom or production section 16
which may be horizontal or angularly oriented relative to the
horizontal located within the production zone 6. After the wellbore
10 is drilled the production tubing 20 is of the hydrocarbon well
is formed of a plurality of alternating liner or casing 22 sections
and in line valve bodies 24 surrounded by a layer of cement 23
between the casing and the wellbore. The valve bodies 24 are
adapted to control fluid flow from the surrounding formation
proximate to that valve body and may be located at predetermined
locations to correspond to a desired production zone within the
wellbore. In operation, between 8 and 100 valve bodies may be
utilized within a wellbore although it will be appreciated that
other quantities may be useful as well.
[0036] Turning now to FIG. 2, a perspective view of one valve body
24 is illustrated. The valve body 24 comprises a substantially
elongate cylindrical outer casing 26 extending between first and
second ends 28 and 30, respectively and having a central passage 32
therethrough. The first end 28 of the valve body is connected to
adjacent liner or casing section 22 with an internal threading in
the first end 28. The second end 30 of the valve body is connected
to an adjacent casing section with external threading around the
second end 30. The valve body 24 further includes a central portion
34 having a plurality of raised sections 36 extending axially
therealong with passages 37 therebetween. As illustrated in the
accompanying figures, the valve body 24 has three raised sections
although it will be appreciated that a different number may also be
utilized.
[0037] Each raised section 36 includes a radially movable body or
port body 38 therein having an aperture 40 extending therethrough.
The aperture 40 extends from the exterior to the interior of the
valve body and is adapted to provide a fluid passage between the
interior of the bottom section 16 and the wellbore 10 as will be
further described below. The aperture 40 may be filled with a
sealing body (not shown) when installed within a bottom section 16.
The sealing body serves to assist in sealing the aperture until the
formation is to be fractured and therefore will have sufficient
strength to remain within the aperture until that time and will
also be sufficiently frangible so as to be fractured and removed
from the aperture during the fracing process. Additionally, the
port bodies 38 are radially extendable from the valve body so as to
engage an outer surface thereof against the wellbore 10 so as to
center the valve body 24 and thereby the production section within
the wellbore.
[0038] Turning now to FIG. 3, a cross sectional view of the valve
body 24 is illustrated. The central passage 32 of the valve body
includes a central portion 42 corresponding to the location of the
port bodies 38. The central portion is substantially cylindrical
and contains a sliding sleeve 44 therein. The central portion 42 is
defined between first or entrance and second or exit raised
portions or annular shoulders, 46 and 48, respectively. The sliding
sleeve 44 is longitudinally displaceable within the central portion
42 to either be adjacent to the first or second shoulder 46 or 48.
At a location adjacent to the second shoulder, the sliding sleeve
44 sealably covers the apertures 40 so as to isolate the interior
from the exterior of the bottom section 16 from each other, whereas
when the sliding sleeve 44 is adjacent to the first shoulder 46,
the sliding sleeve 44
[0039] The central portion 42 includes a first annular groove 50a
therein proximate to the first shoulder 46. The sliding sleeve 44
includes a radially disposed snap ring 52 therein corresponding to
the groove 50a so as to engage therewith and retain the sliding
sleeve 44 proximate to the first shoulder 46 which is an open
position for the valve body 24. The central portion 42 also
includes a second annular groove 50b therein proximate to the
aperture 40 having a similar profile to the first annular groove
50a. The snap ring 52 of the sleeve is receivable in either the
first or second annular groove 50a or 50b such that the sleeve is
held in either an open position as illustrated in FIG. 5 or a
closed position as illustrated in FIG. 4. The sliding sleeve 44
also includes annular wiper seals 54 which will be described more
fully below proximate to either end thereof to maintain a fluid
tight seal between the sliding sleeve and the interior of the
central portion 42.
[0040] The port bodies 38 are slidably received within the valve
body 24 so as to be radially extendable therefrom. As illustrated
in FIG. 3, the port bodies are located in their retracted position
such that an exterior surface 60 of the port bodies is aligned with
an exterior surface 62 of the raised sections 36. Each raised
section may also include limit plates 64 located to each side of
the port bodies 38 which overlap a portion of and retain pistons
within the cylinders as are more fully described below.
[0041] Each raised section 36 includes at least one void region or
cylinder 66 disposed radially therein. Each cylinder 66 includes a
piston 68 therein which is operably connected to a corresponding
port body 38 forming an actuator for selectably moving the port
bodies 38. Turning now to FIGS. 4 and 5, detailed views of one port
body 38 are illustrated at a retracted and extended position,
respectively. Each port body 38 may have an opposed pair of pistons
68 associated therewith arranged to opposed longitudinal sides of
the valve body 24. It will be appreciated that other quantities of
pistons 68 may also be utilized for each port body 38 as well. The
pistons 68 are connected to the valve body by a top plate 70 having
an exterior surface 72. The exterior surface 72 is positioned to
correspond to the exterior surface 62 of the raised sections 36 so
as to present a substantially continuous surface therewith when the
port bodies 38 are in their retracted positions. The exterior
surface 72 also includes angled end portions 74 so as to provide a
ramp or inclined surface at each end of the port body 38 when the
port bodies 38 are in an extended position. This will assist in
enabling the valve body to be longitudinally displaced within a
wellbore 10 with the vertical section 12 under thermal expansion of
the production string and thereby to minimize any shear stresses on
the port body 38.
[0042] The pistons 68 are radially moveable within the cylinders
relative to a central axis of the valve body so as to be radially
extendable therefrom. In the extended position illustrated in FIG.
5, the exterior surface 72 of the port bodies are adapted to be in
contact with the wellbore 10 so as to extend the port body 38 and
thereby enable the wellbore 10 to be placed in fluidic
communication with the central portion 42 of the valve body 24. The
pistons 68 may have a travel distance between their retracted
positions and their extended positions of between 0.10 and 0.50
inches although it will be appreciated that other distances may
also be possible. In the extended position, it will be possible to
frac that location without having to also fracture the concrete
which will be located between the valve body 24 and the wellbore
wall thereby reducing the required frac pressure. Additionally,
more than one port body 38 may be utilized and radially arranged
around the valve body so as to centre the valve body within the
wellbore when the port bodies are extended therefrom.
[0043] The pistons 68 may include seals 76 therearound so as to
seal the piston within the cylinders 66. Additionally, the port
body 38 may include a port sleeve 78 extending radially inward
through a corresponding port bore 81 within the valve body. A seal
80 may be located between the port sleeve 78 and the port bore 81
so as to provide a fluid tight seal therebetween. A snap ring 82
may be provided within the port bore 81 adapted to bear radially
inwardly upon the port sleeve 78. In the extended position, the
snap ring 82 compresses radially inwardly to provide a shoulder
upon which the port sleeve 78 may rest so as to prevent retraction
of the port body 38 as illustrated in FIG. 5. The pistons 68 may be
displaceable within the cylinders 66 by the introduction of a
pressurized fluid into a bottom portion thereof. It will also be
appreciated that other sleeve valves may be utilized which do not
include extendable pistons as illustrated herein as are commonly
known in the art.
[0044] With reference to FIG. 3, the entrance bore 94 intersect the
central passage 32 of the valve body 24. As illustrated each
entrance bore 94 may be covered by a knock-out plug 102 so as to
seal the entrance bore until removed. In operation, as concrete is
pumped down the bottom section 16, it will be followed by a plug so
as to provide an end to the volume of concrete. The plug is
pressurized by a pumping fluid (such as water, by way of
non-limiting example) so as to force the concrete down the
production string and thereafter to be extruded into the annulus
between the horizontal section and the wellbore. The knock-out
plugs 102 are designed so as to be removed or knocked-out of the
entrance bore by the concrete plug passing thereby. In such a way,
once the concrete has passed the valve body 24, the concrete plug
removes the knock-out plugs 102 so as to pressurize the entrance
bore 94 and fluid bore 90 and thereafter to extend the pistons 68
from the valve body 24 once the pressurizing fluid has reached a
sufficient pressure.
[0045] Turning now to FIG. 6, a shifting tool 200 is illustrated
within the central passage 32 of the valve body 24. The shifting
tool 200 is adapted to engage the sliding sleeve 44 and shift it
between a closed position as illustrated in FIG. 4 and an open
position in which the apertures 40 are uncovered by the sliding
sleeve 44 so as to permit fluid flow between and interior and an
exterior of the valve body 24 as illustrated in FIG. 5. The
shifting tool 200 comprises a substantially cylindrical elongate
tubular body 202 extending between first and second ends 204 and
206, respectively. The shifting tool 200 includes a central bore
210 therethrough (shown in FIGS. 7 through 9) to receive an
actuator or to permit the passage of fluids and other tools
therethrough. The shifting tool 200 includes at least one sleeve
engaging member 208 radially extendable from the tubular body 202
so as to be selectably engageable with the sliding sleeve 44 of the
valve body 24. As illustrated in the accompanying figures, three
sleeve engaging members 208 are illustrated although it will be
appreciated that other quantities may be useful as well.
[0046] The sleeve engaging members 208 comprise elongate members
extending substantially parallel to a central axis 209 of the
shifting tool between first and second ends 212 and 214,
respectively. The first and second ends 212 and 214 include first
and second catches 216 and 218, respectively for surrounding the
sliding sleeve and engaging a corresponding first or second end 43
or 45, respectively of the sliding sleeve 44 depending upon which
direction the shifting tool 200 is displaced within the valve body
24. As illustrated in FIGS. 8 and 9, the first and second catches
216 and 218 of the sleeve engaging member 208 each include and
inclined surface 220 and 222, respectively facing in opposed
directions from each other. The inclined surfaces 220 and 222 are
adapted to engage upon either the first or second annular shoulder
46 or 48 of the valve body as the shifting tool 200 is pulled or
pushed there into. The first or second annular shoulders 46 or 48
press the first or second inclined surface 220 or 222 radially
inwardly so as to press the sleeve engaging members 208 inwardly
and thereby to disengage the sleeve engaging members 208 from the
sliding sleeve 44 when the sliding sleeve 44 has been shifted to a
desired position proximate to one of the annular shoulders. In an
optional embodiment, one or both of the catches 216 or 218 may have
an extended length as illustrated in FIG. 10 such that the sleeve
engaging members are disengaged from the sliding sleeve at a
position spaced apart from one of the first or second annular
shoulders 46 or 48 and thereby adapted to position the sliding
sleeve at a third or central position within the valve body 24.
[0047] Turning to FIG. 7, the sleeve engaging members are
maintained parallel to the tubular body 202 of the shifting tool
200 by a parallel shaft 230. Each parallel shaft 230 is linked to a
sleeve engaging member 208 by a pair of spaced apart linking arms
232. The parallel shaft 230 is rotatably supported within the
shifting tool tubular body 202 by bearings or the like. The linking
arms 232 are fixedly attached to the parallel shaft 230 at a
proximate end and are received within a blind bore 234 of the
sleeve engaging members 208. As illustrated in FIG. 6, the linking
arms 232 are longitudinally spaced apart from each other along the
parallel shaft 230 and the sleeve engaging member 208 so as to be
proximate to the first and second ends 212 and 214 of the sleeve
engaging member 208.
[0048] Turning now to FIG. 8, the tubular body 202 of the shifting
tool includes a shifting bore 226 therein at a location
corresponding to each sleeve engaging member. The shifting bore 226
extends from a cavity receiving the sleeve engaging member to the
central bore 210 of the shifting tool 200. Each sleeve engaging
member 208 includes a piston 224 extending radially therefrom which
is received within the shifting bore 226. In operation, a fluid
pressure applied to the central bore 210 of the shifting tool will
be applied to the piston 224 so as to extend the piston within the
shifting bore 226 and thereby to extend the sleeve engaging members
208 from a first or retracted position within the shifting tool
tubular body 202 as illustrated in FIG. 8 to a second or extended
position for engagement on the sliding sleeve 44 as discussed above
as illustrated in FIG. 9. The parallel shafts also include helical
springs (not shown) thereon to bias the sleeve engaging members to
the retracted position.
[0049] The first end 204 of the shifting tool 200 includes an
internal threading 236 therein for connection to the external
threading of the end of a production string or pipe (not shown).
The second end 206 of the shifting tool 200 includes external
threading 238 for connection to internal threading of a downstream
productions string or further tools, such as by way of non-limiting
example a control valve as will be discussed below. An end cap 240
may be located over the external threading 238 when such a
downstream connection is not utilized.
[0050] With reference to FIGS. 8 and 9, a first control valve 300
according to a first embodiment located within a shifting tool 200
for use in wells having low hydrocarbon production flow rates. The
low flow control valve 300 comprises a valve housing 302 having a
valve passage 304 therethrough and seals 344 therearound for
sealing the valve housing 302 within the shifting tool 200. The low
flow control valve 300 includes a central housing extension 306
extending axially within the valve passage 304 and a spring housing
portion 320 downstream of the central portion 310. The central
housing extension 306 includes an end cap 308 separating an
entrance end of the valve passage from a central portion 310 of the
valve passage and an inlet bore 322 permitting a fluid to enter the
central portion 310 from the valve passage 304.
[0051] The central portion 310 of the valve passage contains a
valve piston rod 312 slidably located therein. The valve piston rod
312 includes leading and trailing pistons, 314 and 316,
respectively thereon in sealed sliding contact with the central
portion 310 of the valve passage. The leading piston 314 forms a
first chamber 313 with the end cap 308 having an inlet port 315
extending through the leading piston 314. The valve piston rod 312
also includes a leading extension 318 having an end surface 321
extending from an upstream end thereof and extending through the
end cap 308. The valve piston rod 312 is slidable within the
central portion 310 between a closed position as illustrated in
FIG. 8 and an open position as illustrated in FIG. 9. In the closed
position, the second or trailing piston 316 is sealable against the
end of the central portion 310 to close or seal the end of the
central passage and thereby prevent the flow of a fluid through the
control valve. In the open position as illustrated in FIG. 9, the
trailing piston 316 is disengagable from the end of the central
portion 310 so as to provide a path of flow, generally indicated at
319, therethrough from the central passage to the spring
housing.
[0052] A spring 324 is located within the spring housing 320 and
extends from the valve piston rod 312 to an orifice plate 326 at a
downstream end of the spring housing 320. The spring 324 biases the
valve piston rod 312 towards the closed position as illustrated in
FIG. 8. Shims or the like may be provided between the spring 324
and the orifice plate 326 so as to adjust the force exerted by the
spring upon the valve piston rod 312. In other embodiments, the
orifice plate may be axially moveable within the valve body by
threading or the like to adjust the force exerted by the spring. In
operation, fluid pumped down the production string to the valve
passage 304 passes through the inlet bore and into the central
portion 310. The pressure of the fluid within the central portion
310 is balanced upon the opposed faces of leading and trailing
pistons 314 and 316 such that the net pressure exerted upon the
valve piston rod 312 is provided by the pressure exerted on the end
surface 321 of the leading extension 318 and on the leading piston
314 from within the first chamber 313. The resulting force exerted
upon the end surface 321 is resisted by the biasing force provided
by the spring 324 as described above.
[0053] Additionally, the orifice plate 326 includes an orifice 328
therethrough selected to provide a pressure differential
thereacross under a desired fluid flow rate. In this way, when the
fluid is flowing through the central portion 310 and the spring
housing 320, the spring housing 320 will have a pressure developed
therein due to the orifice plate. This pressure developed within
the spring housing 320 will be transmitted through apertures 330
within the spring housing to a sealed region 332 around the spring
housing proximate to the shifting bore 226 of the shifting tool
200. This pressure serves to extend the pistons 224 within the
shifting bores 226 and thereby to extend the sleeve engaging
members 208 from the shifting tool. The pressure developed within
the spring housing 320 also resists the opening of the valve piston
rod 312 such that in order for the valve to open and remain open,
the pressure applied to the entrance of the valve passage 304 is
required to overcome both the biasing force of the spring 324 and
the pressure created within the spring housing 320 by the orifice
328.
[0054] The valve 300 may be closed by reducing the pressure of the
supplied fluid to below the pressure required to overcome the
spring 324 and the pressured created by the orifice 328 such that
the spring is permitted to close the valve 300 by returning the
valve piston rod 312 to the closed position as illustrate in 11 as
well as permitting the springs on the parallel shaft 230 to retract
the sleeve engaging members 208 as the pressure within the spring
housing 320 is reduced. Seals 336 as further described below may
also be utilized to seal the contact between the spring housing 320
and the interior of the central bore 210 of the shifting tool
200.
[0055] A shear sleeve 340 may be secured to the outer surface of
the valve housing 302 by shear screws 342 or the like. The sheer
sleeve 340 is sized and selected to be retained between a pipe
threaded into the internal threading 236 of the shifting tool 200
and the remainder of the shifting tool body. In such a way, should
the valve be required to be retrieved, a spherical object 334, such
as a steel ball, such as are commonly known in the art may be
dropped down the production string so as to obstruct the valve
passage 304 of the valve 300. Obstructing the flow of a fluid
through the valve passage 304 will cause a pressure to develop
above the valve so as to shear the shear screws 342 and force the
valve through the shifting tool. The strength of the sheer screws
342 may be selected so as to prevent their being sheered during
normal operation of the valve 300 such as for pressures of between
1000 and 3000 psi inlet fluid pressure. The valve illustrated in
FIGS. 8 and 9 is adapted for use in a low hydrocarbon flow rate
well. In such well types, the flow of fluids such as hydrocarbons
or other fluids is low enough that the fluid pumped down the well
to pressurize the central portion 310 is sufficient to overcome the
flow of the fluids up the well so as to pass through the orifice
328. It will be appreciated that for wells of higher well pressure
or flow rates, such a valve will be limited in its application.
[0056] In embodiments, the method for completing a well involves an
apparatus for selectably opening a valve body in a well casing
having a central passage and a plurality of apertures therethrough.
The apparatus comprises a sleeve slidably located within the
central passage of the valve body adapted to selectably cover or
uncover the apertures and a shifting tool slidably locatable within
the sleeve. The apparatus further comprises at least one sleeve
engaging member selectably extendable from the shifting tool in
parallel to a central axis of the shifting tool and engagable upon
the sleeve wherein the shifting tool is moveable so as to cause the
sleeve to selectably cover and uncover the apertures.
[0057] The sleeve may be axially displaceable within the central
passage. The sleeve may be displacable between a first position
covering the apertures and a second position uncovering the
apertures. The sleeve may seal the apertures in the first
position.
[0058] The shifting tool may be securable to the end of a
production casing nested within the well casing. The shifting tool
may include a central bore therethrough. The central bore may
include a plurality of shifting bores extending therefrom, each
shifting bore having a piston therein operably connected to a
sleeve engaging member for extending the sleeve engaging member
when the central bore is supplied with a pressurized fluid.
[0059] The sleeve engaging members may comprise elongate members
extending between first and second ends. The sleeve engaging
members may extend parallel to an axis of the central bore. The
first and second ends of the sleeve engaging members may include
first and second catches for engaging corresponding first and
second ends of the sleeve. The first and second catches may be
spaced apart by a distance sufficient or receive the sleeve
therebetween.
[0060] The first and second ends of the elongate members may
include corresponding first and second inclined surfaces. The
central passage may include a raised portion proximate to the first
position of the sleeve so as to be engaged by the first inclined
surface as the sleeve is moved into the first position and thereby
to disengage the catches from the sleeve. The central passage may
include a raised portion proximate to the second position of the
sleeve so as to be engaged by the second inclined surface as the
sleeve is moved into second first position and thereby to disengage
the catches from the sleeve.
[0061] Each sleeve engaging member may include a shaft extending
therealong and at least two linking arms extending from the shaft
to the sleeve engaging member so as to maintain the sleeve engaging
member parallel thereto. The linking arms may be received within
sockets within the sleeve engaging member.
[0062] According to further embodiments, there is disclosed an
apparatus for shifting a sleeve of a sleeve valve, the sleeve valve
comprising a valve body with at least one aperture extending
therethrough and an axially displaceable sleeve adapted to
selectably cover or uncover the apertures. The apparatus comprises
a shifting tool slidably locatable within the sleeve and at least
one sleeve engaging member selectably extendable from the shifting
tool in parallel a central axis of the shifting tool and engagable
upon the sleeve.
[0063] According to further embodiments, there is disclosed a
method for selectably opening a valve body in a well casing having
a central passage and a plurality of apertures therethrough. The
method comprises providing a sleeve slidably located within the
central passage of the valve body adapted to selectably cover or
uncover the apertures. The sleeve is located in one of a first or
second position. The method further comprises positioning an
shifting tool slidably locatable within the sleeve, extending the
at least one sleeve engaging member selectably extendable from the
shifting tool in parallel to a central axis of the shifting tool
into engagement upon the sleeve, and axially moving the shifting
tool and the sleeve to another of the first or second
positions.
[0064] The method may further comprise disengaging the at least one
sleeve engaging member from the sleeve at the other of the first or
second positions.
[0065] According to further embodiments, there is disclosed a
method for actuating a sleeve valve, the sleeve valve comprising a
valve body with at least one aperture extending therethrough and an
axially displaceable sleeve adapted to selectably cover or uncover
the apertures. The method comprises locating a shifting tool within
the sleeve, extending at least one sleeve engaging member from the
shifting tool until engaged upon the sleeve, axially moving the
shifting tool and sleeve and retracting the sleeve engaging member
until disengaged from the sleeve.
[0066] According to further embodiments, there is disclosed a
method for applying a fluid actuation pressure to a portion of an
actuator, the method comprising sealably locating a valve body
within the interior of the actuator, the valve body having an
interior cavity therein and applying a fluid pressure to an
upstream end of the valve body. The method further comprises
slidably displacing a piston within the interior cavity after the
fluid pressure reaches a desired pressure so as to open a fluid
path through the valve body and passing the fluid through ports in
an exterior of the valve body to provide the supply pressure to the
actuator.
[0067] According to further embodiments, there is disclosed an
apparatus for applying a fluid actuation pressure to a portion of
an actuator comprising a valve body sealably locatable within the
interior of the actuator, having an interior cavity. The valve body
has a cylinder portion and a spring housing portion. The spring
housing portion has a plurality of ports therethrough at a location
corresponding to the actuator. The apparatus further includes an
entrance end for applying a fluid pressure to an upstream end of
the valve body and a rod slidably locatable within the cylinder
portion. The entrance end is in fluidic communication with the
cylinder portion. The rod has a piston sealed within the interior
of the cylinder portion, the rod and piston displaceable to an
actuating position wherein the piston is displaced out of the
cylinder portion so as to place the entrance end in fluidic
communication with the spring housing portion. The apparatus
further comprises a compression spring engaged against a downstream
portion of the rod and piston so as to bias the rod and piston into
a closed position within the cylinder portion and an outlet orifice
at a downstream end of the spring portion so as to release fluid
from the spring housing at a desired rate.
[0068] According to further embodiments, there is disclosed a
method for applying a fluid actuation pressure to a portion of an
actuator. The method comprises sealably securing a valve body to a
distal end of the actuator and pumping a pressurized fluid through
the valve body and actuator so as to provide an actuation pressure
to the actuator.
[0069] According to further embodiments, there is disclosed a
method for opening a passage through a terminal end of a production
string. The method comprises providing a valve body at a distal end
of the production string, providing an actuation pressure to
actuation fluid within the so as to open a flap at a distal end
thereof. The flap being operably connected to an annular piston
longitudinally displaceable within the valve body and being biased
with a spring so as to bias the flap to a closed position.
[0070] According to further embodiments, there is disclosed an
apparatus for selectably sealing and pressurizing a production
string. The apparatus comprises a valve body connectable to a
distal end of a production string, the valve body having an
interior cavity in fluidic communication with the production string
and an annulus between the valve body and the well casing and a
flapper valve rotatably located at a distal end of the interior
cavity at a distal end of the valve body. The apparatus further
comprises a spring biased piston longitudinally displaceable within
the valve body, the piston operatively connected to the flapper
valve so as to bias the flapper valve to a closed position and be
openable when a fluid is pumped through the interior cavity.
[0071] In embodiments the string is supplemented with a cleaning
equipment, thus enabling to prepare the wellbore for stimulation
and to begin operation directly after cleaning. In the art, this
type of operation would have imposed for example a coiled tubing
lowering a first toolstring comprising a mill and motor, or other
cleanout bottom hole assembly such as cleanout nozzle or Junk
Basket, to assure well cleaning conditions prior to replacing the
with toolstring with a further toolstring comprising the completion
equipment such as a shifting-tool to manipulate specific sleeves in
the wellbore; once well is ready, the shifting tool would be run in
the hole next.
[0072] The current disclosure describes a bottom hole assembly
enabling such efficiency by combining a mill equipment with a motor
and a shifting tool for actuating the sleeves installed in the
casing. An exemplary embodiment illustrated in FIG. 11 where the
bottom hole assembly 500 (also sometimes referred to as tool
string) comprise a connector or joint 502 to connect the assembly
to the conveyance mean which may be for example a coiled tubing.
Then optionally some centralizers 504 may be present. The bottom
hole assembly 500 may also include an optional mechanical
disconnect mean 506 and/or a hydraulic disconnect mean 508 as are
commonly known and an optional circulation sub 510 followed by the
shifting 200 equipment useful for selectively activating the
sleeves in later operations as set out above. An orifice sub 512
may also present then the downhole motor 514 to empower the mill
516 which will effectively destroy or drill potential remaining
debris. The circulation sub 510 may be optional, however, it offer
at least another potential circulation path for the fluid which may
be useful for example when the primary flow path becomes blocked or
obstructed; in such situation the circulation sub may be opened for
example by either flow or pressure to re-establish full
circulation. In embodiments, the circulation sub may also be used
when a nitrogen lift, to help the well flow following the
fracturing treatment, is needed. The circulation sub may be
actuated to prevent pumping the nitrogen through the motor thus
extending the life of the motor.
[0073] In embodiments, the motor is conveyed by coiled tubing or
joint pipe. The mill is driven by the motor which is actuated
depending on the pump rate used examples of suitable flow rate may
be from 60 galUS/min to 119 galUS/min. The motor is actuated by
flow rate, which creates relative rotation between the rotor
rolling in the inner wall of the stator. This eccentric motion is
translated to rotation by way of a flexshaft in the transmission
section of the motor. This in turn powers the bit or mill below the
motor. The flow rate required to actuate the motor is a function of
the number of stages in the motor power section (combination of
rotor and stator), the lobe configuration of the motor power
section and the clearance between the rotor and inner wall of the
stator (referred to as `fit`). The operator can choose to actuate
the motor in order to rotate the mill while lowering down the tool
or the mill might be rotated at any specific location where a
sleeve should then be opened or the operator may lower down the
whole bottom hole assembly until encountering a restriction. In the
latter case, the operator would then actuate the motor in order to
clean the restriction and then further continue the hydraulic
fracturing by opening the targeted sleeve.
[0074] In embodiments, the shifting tool may be actuated at flow
rate superior to the flow rates suitable to actuate the motor. In
embodiments the shifting tool may be actuated at flow rates above
120 galUS/min, or above 130 gal US/min, or between 130 galUS/min
and 160 galUS/min. These values may be modified according to the
well operating conditions. This may be achieved with a circulation
device, such as an annular circulation device, a multi-cycle
circulation device, a tubing pressure circulation device, an inline
universal valve, a ported sub or a burst disc (collectively
referred to as a "circulation device"). The circulation device may
be located between the shifting tool and motor (513 in FIG. 11).
During the cleanout operation, flow will be directed through the
motor, actuating the motor without extending the shifting tool
keys. When the flow rate is elevated above a predetermined value,
the increased differential pressure will activate the circulation
device, which will divert flow away from the motor, to the wellbore
annulus. The rate can then be increased beyond the range of the
motor and allow full extension of the shifting tool keys for sleeve
manipulation. The circulating device may or may not be resettable,
depending on device used and objectives. If device is resettable,
flow to the motor may be restored upon reduction of pump rate. If
device is not resettable, flow path will continue to the annulus,
however shifting tool keys can be retracted with slight reduction
in flow rate.
[0075] Fracturing operations could then start at any location in
the well; for example from toe-to-heel, or from heel-to-toe or at
any preferred location by opening the sleeve corresponding to the
chosen zone to be fracture; then, the fluid pressure would be
increased until reaching the fracturing pressure of the formation.
The created fracture may then be propped with the fracturing fluid
and when the operator decides to move to another zone, the
activation device will then be used to reclose the opened sleeve,
thus isolating the treated zone. This will be repeated until the
amount of targeted zone has been treated; at any time if a
restriction is encountered, the mill might be used.
[0076] Accordingly, each zone may be fractured independently and
then isolated after the fracture is complete. The reclosing sleeve
enables to fracture and isolate each specific zone without using
any isolation (or sealing) elements such as packer, isolation plug,
or cups. Combined with a cleaning equipment (motor and mill); this
would make the pin-point fracturing technique much more efficient
and reliable than the current techniques involving setting and
unsetting a packer for each zone or even having to run a cleaning
stage before initiating any fracturing operations. While taking
into account that in many of past fracturing operations, the use of
sealing elements such as packer have been the source of problems,
the currently disclosed methods alleviate questions about
reliability of sealing element and one of the many further
advantages is that it would also not require having a toe valve or
opening to run in equipment. The sleeve is reclosed after
fracture/stimulation to provide pressure integrity back to the
casing string. This opens up the opportunity to fracture/stimulate
the wellbore in any fashion. Then, by removing the sealing element,
there will no longer needs to be a washing step for cleaning the
sealing elements thus reducing fluid consumption, suppressing
overflush which will contribute to better fracturing jobs.
[0077] In embodiment, the actuation device is mounted on a coiled
tubing element. The coiled tubing may remain in the wellbore during
the fracture/stimulation. Once all the zones are
fractured/stimulated the coil tubing may be lowered to the toe of
the well. During this time, the clean out of the well can be
performed without having to change any part of the Bottom Hole
Assembly (BHA) to ensure all debris and sand are washed from the
wellbore.
[0078] Once the cleanout is completed, the actuation device is put
in opening position and the coil tubing is pulled out of the well.
The upward motion would open all the sleeves coming out of the well
leaving the well clean and ready for production.
[0079] While the present disclosure has been disclosed with respect
to a limited number of embodiments, those skilled in the art,
having the benefit of this disclosure, will appreciate numerous
modifications and variations there from. It is intended that the
appended claims cover such modifications and variations as fall
within the true spirit and scope of the disclosure.
* * * * *