U.S. patent application number 13/659641 was filed with the patent office on 2014-04-24 for erodable bridge plug in fracturing applications.
The applicant listed for this patent is Henry Joe Jordan, JR.. Invention is credited to Henry Joe Jordan, JR..
Application Number | 20140110112 13/659641 |
Document ID | / |
Family ID | 50484290 |
Filed Date | 2014-04-24 |
United States Patent
Application |
20140110112 |
Kind Code |
A1 |
Jordan, JR.; Henry Joe |
April 24, 2014 |
Erodable Bridge Plug in Fracturing Applications
Abstract
In order to overcome the need to remove each packer after a plug
and perforate operation in order to produce a well it is desirable
to utilize an erodible packer that may allow one way flow. An
erodible packer may be constructed of a material such as
polyglycolic acid as a binder. The same packer may also allow one
way flow past the packer, such as flow from the casing below the
packer to the casing above the packer. The packer may erode upon
the expiration of a predetermined period of time or upon exposure
to an activating agent.
Inventors: |
Jordan, JR.; Henry Joe;
(Willis, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Jordan, JR.; Henry Joe |
Willis |
TX |
US |
|
|
Family ID: |
50484290 |
Appl. No.: |
13/659641 |
Filed: |
October 24, 2012 |
Current U.S.
Class: |
166/281 ;
166/179; 166/193 |
Current CPC
Class: |
E21B 33/12 20130101;
E21B 33/1293 20130101; E21B 43/261 20130101; E21B 34/14
20130101 |
Class at
Publication: |
166/281 ;
166/179; 166/193 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 43/26 20060101 E21B043/26 |
Claims
1. A packer deployed in a wellbore comprising: a mandrel having an
interior throughbore and an exterior; a one way valve in the
interior throughbore of the mandrel; wherein the one way valve is
closed to prevent fluid above the valve from passing the one way
valve and is opened to allow fluid from below the valve to pass the
one way valve; a sealing element; wherein the sealing element is
attached to the exterior of the mandrel; and an anchor; wherein the
anchor fixes the mandrel in place longitudinally.
2. The packer of claim 1 wherein the one way valve is a flapper
valve.
3. The packer of claim 1 wherein the one way valve is a ball and
seat.
4. The packer of claim 1 wherein the mandrel is at least partially
an erodible material.
5. The packer of claim 4 wherein the mandrel is a combination of at
least the erodible material and a polymer.
6. The packer of claim 4 wherein the mandrel is a combination of at
least the erodible material and a fiber.
7. The packer of claim 4 wherein the erodible material is
polyglycolic acid.
8. The packer of claim 4 wherein the erodible material is
hydrocarbon soluble.
9. A downhole assembly comprising: a packer having a mandrel, a one
way valve, a sealing element, and an anchor; wherein the mandrel
has an interior throughbore and an exterior; wherein the one way
valve is in the interior throughbore of the mandrel; further
wherein the one way valve is closed to prevent fluid above the
valve from passing the one way valve and is opened to allow fluid
from below the valve to pass the one way valve; wherein the a
sealing element is attached to the exterior of the mandrel; and
wherein the anchor fixes the mandrel in place longitudinally.
10. The packer of claim 9 wherein the one way valve is a flapper
valve.
11. The packer of claim 9 wherein the one way valve is a ball and
seat.
12. A downhole assembly comprising: a packer having a mandrel, a
sealing element, and an anchor; wherein the mandrel has an interior
throughbore and an exterior; wherein the sealing element is
attached to the exterior of the mandrel; wherein the anchor fixes
the mandrel in place longitudinally; and wherein the packer is at
least partially an erodible material
13. The packer of claim 12 wherein the packer is at least partially
a combination of the erodible material and a polymer.
14. The packer of claim 12 wherein the packer is at least partially
a combination of the erodible material and a fiber.
15. The packer of claim 14 wherein the fiber is glass fiber.
16. The packer of claim 14 wherein the fiber is carbon fiber.
17. The packer of claim 12 wherein the erodible material is
polyglycolic acid.
18. The packer of claim 12 wherein the erodible material is
hydrocarbon soluble.
19. A method of completing a well comprising: pumping a bottom hole
assembly into a well; setting a packer; wherein the packer has a
mandrel having a throughbore; further wherein a one way valve is
located in the throughbore; perforating the well pumping in at
least a second bottomhole assembly; setting the second packer;
wherein the second packer has a second mandrel having a second
throughbore with a second one way valve in the second throughbore;
and producing the well.
20. The packer of claim 19 wherein the one way valve is a flapper
valve.
21. The packer of claim 19 wherein the one way valve is a ball and
seat.
22. The packer of claim 19 wherein the mandrel is at least
partially an erodible material.
23. The packer of claim 22 wherein the mandrel is a combination of
at least the erodible material and a polymer.
24. The packer of claim 22 wherein the mandrel is a combination of
at least the erodible material and a fiber.
25. The packer of claim 22 wherein the erodible material is
polyglycolic acid.
26. The packer of claim 22 wherein the erodible material is
hydrocarbon soluble.
Description
BACKGROUND
[0001] In the course of producing oil and gas wells, typically
after the well is drilled the well may be completed. In many
instances, in order to complete the well the well may be cased. In
certain instances the process of installing casing into the
wellbore may begin with a wet shoe placed at the lowest section of
the casing. The casing may then be run into the wellbore.
[0002] Once the casing is located at the appropriate position in
the wellbore cement may be pumped into down the interior of the
casing. The cement may both anchor the casing into position as well
as isolate the hydrocarbon bearing formation from another section
of the same formation or from other formations that are penetrated
by the same wellbore. Once the cement reaches the wet shoe the
cement flows out of the casing and then into the annular area
outside of the casing between the casing and the wellbore. The
cement is forced into the annular area generally until the annular
area is filled with cement. Once an appropriate amount of cement is
pumped into the casing a wiper plug may then be used push the
cement out of the casing and to eliminate as much of the remaining
cement as possible from the interior of the casing.
[0003] Generally the next step in completing the well, after the
cement is allowed to set or cure is to form ports in the casing to
allow the fluids from the formation into the interior of the
casing. One of the current methods of forming the ports in the
casing is known as plug and perforate. Typically, to plug and
perforate a casing a perforation assembly consisting of a packer, a
setting tool, and a perforation gun are run into the casing
together on an electric line. The perforation gun will typically
have several sections or perforating charges on the same gun so
that the perforation gun may be discharged multiple times, five
sections per gun is usual.
[0004] The perforation assembly is lowered into the wellbore until
it is located appropriately. Usually the packer will be located
below the section of a formation is to be completed. With the
packer in place the setting tool is activated to lock the packer
into position and to seal the casing below the packer from the
wellbore above the packer. The perforation gun and setting tool are
then disconnected from the packer and may be moved uphole some
distance where the first section of the perforating gun is
discharged to form ports in the casing and through the cement to
the formation. The perforating gun and setting tool are again moved
some distance up the casing and the perforating gun is again
activated. The process may be repeated until all of the perforating
gun's sections have been utilized.
[0005] Once the perforating gun's sections been expended the
perforating gun and the setting tool are removed from the casing.
The formation may then be fractured and otherwise treated with the
packer that was placed into the casing isolating the casing below
the packer and allowing only the portion of the formation that was
accessed by the perforating gun to be fractured.
[0006] After fracturing the formation a new perforation assembly is
run into the casing where the new packer is set above the section
previously perforated and the entire process is repeated until the
desired number of perforations has been completed and the
associated portions of the formations have been fractured and
treated.
[0007] Once the process is complete the packers must be removed,
typically by milling or drilling out each packer. It is not unusual
for there to be ten or more packers that must be removed before the
well may be produced. Removing each packer by milling it out takes
a substantial amount of rig time incurring substantial cost.
[0008] It is desirable to be able to remove the packers from the
casing without milling out each packer.
SUMMARY
[0009] In an embodiment of the present invention an erodible packer
that seals the wellbore to block flow from above the packer to
below the packer.
[0010] A first embodiment may consist of an easily erodible packer
containing components that allow the packer to be anchored in place
while allowing pressure isolation in one direction. The easily
erodible packer may allow flow from below the packer to pass
through the packer once the well is put on production. The flow
from the formation into the casing and to the surface may carry the
packer out of the well as it erodes eventually leading to full bore
production from the well.
[0011] A packer deployed in a wellbore comprising a mandrel having
an interior throughbore and an exterior. A one way valve may be in
the interior throughbore of the mandrel. The one way valve may be
closed to prevent fluid from above the valve from passing the one
way valve and may be opened to allow fluid from below the valve to
pass the one way valve. The packer has a sealing element is
attached to the exterior of the mandrel and the packer has an
anchor where the anchor fixes the mandrel in place
longitudinally.
[0012] The packer's one way valve may be a flapper valve or it
could be a ball and seat type valve. In some instances the mandrel
is at least partially an erodible material, a combination of at
least the erodible material and a polymer, or even a combination of
at least the erodible material and a fiber. The erodible material
may be polyglycolic acid or hydrocarbon soluble.
[0013] A downhole assembly may be a packer having a mandrel, a one
way valve, a sealing element, and an anchor. The mandrel may have
an interior throughbore and an exterior. A one way valve may be in
the interior throughbore of the mandrel. The one way valve may be
closed to prevent fluid from above the valve from passing the one
way valve and may be opened to allow fluid from below the valve to
pass the one way valve. A sealing element may be attached to the
exterior of the mandrel; and the anchor may fix the mandrel in
place longitudinally. The packer's one way valve may be a flapper
valve or it may be a ball and seat type of valve.
[0014] A downhole assembly may be a packer having a mandrel, a
sealing element, and an anchor. The mandrel may have an interior
throughbore and an exterior. The sealing element may be attached to
the exterior of the mandrel. The anchor may fix the mandrel in
place longitudinally. The packer may be at least partially
constructed of an erodible material.
[0015] The packer may be at least partially a combination of the
erodible material and a polymer, a combination of the erodible
material and a fiber. In certain instances the fiber may be glass
fiber or it may be carbon fiber. While the erodible material may be
polyglycolic acid or it may be hydrocarbon soluble.
[0016] A method of completing a well may have the steps of pumping
a bottom hole assembly into a well, setting a packer, perforating
the well, pumping in at least a second bottomhole assembly, setting
the second packer, and producing the well. The packer may have a
mandrel having a throughbore and a one way valve may be located in
the throughbore. The second packer has a second mandrel having a
second throughbore with a second one way valve in the second
throughbore.
[0017] In many instances the one way valve may be a flapper valve
or it may be a ball and seat type of valve. The mandrel may be at
least partially an erodible material, a combination of at least the
erodible material and a polymer, or a combination of at least the
erodible material and a fiber. The erodible material may be
polyglycolic acid or it may be hydrocarbon soluble.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] FIG. 1 depicts a previously set packer and perforated casing
section and a newly pumped in second bottom hole assembly.
[0019] FIG. 2 depicts an erodible packer with a one way flapper
valve.
[0020] FIG. 3 depicts an erodible packer with a one way ball and
seat valve.
[0021] FIG. 4 depicts an erodible packer with a one way flapper
valve as it erodes in the presence of wellbore fluid.
DETAILED DESCRIPTION
[0022] The description that follows includes exemplary apparatus,
methods, techniques, and instruction sequences that embody
techniques of the inventive subject matter. However, it is
understood that the described embodiments may be practiced without
these specific details.
[0023] FIG. 1 depicts a completion where a bottom hole assembly 40
has already been pumped into the casing 14 a composite packer 44
has been set and left in position near the bottom of the casing and
the casing perforated by a multi-stage perforating gun 46. As the
initial bottom hole assembly 40 was pumped into the casing 14 the
fluid in the casing ws pushed ahead of the bottom hole assembly 40
and out of the casing 14 and into the adjacent formation via the
wet shoe 16. A second bottom hole assembly 40 is shown on location
in the casing 14 located just above the perforations 52 in the
casing 14.
[0024] A wellbore 10 has been drilled through one or more formation
zones 12. A casing 14 may be run into the wellbore 10. Typically
the casing is assembled on the surface 20 with a wet shoe 16 on the
lower end of the casing 14. The casing 14 and wet shoe 16 are then
lowered into the wellbore 10 by the rig 30 until the desired depth
is reached.
[0025] Upon reaching the desired depth cement 22 is pumped from the
surface 20 through the interior of the casing 14 out of the wet
shoe 16 and into the annular area 24 formed between the casing 14
and the wellbore 10. Once a predetermined amount of cement 22 is
pumped in the casing 14 at the surface 20 a wiper plug may be
pumped down through the casing to push the entire amount of cement
out of the casing 14 and into the annular area 24. Upon setting or
curing the cement 22 may anchor the casing 14 into position as well
as longitudinally isolating the various formations 12 or portions
of a formation 12 from other formations 12 or portions of
formations 12.
[0026] Typically after the casing has been cemented or the various
zones otherwise isolated from one another a bottom hole assembly
may be run into the casing 14 on e-line 50. The bottom hole
assembly 40, typically has a composite plug 42 on the lower end, a
setting tool 44 just above the composite plug 42, and a multi-stage
perforating gun 46 just above the setting tool 44. Once the bottom
hole assembly 40 is properly located power is supplied via the
e-line 50 to the setting tool 44 to set the composite plug 42
thereby blocking the low of fluid past the composite plug 42 is
either direction.
[0027] The setting tool 44 is then disconnected from the composite
plug 42 so that the remainder of the bottom hole assembly 40, the
setting tool 44 and the multi-stage perforating gun 46 may be
raised to the desired location and power supplied to the first
stage of the multi-stage perforating gun 46 so that the first stage
may be discharged to form ports 52 through the casing 14. The
multi-stage perforating gun 46 may then be moved some distance and
the next stage of the multi-stage perforating gun 46 is discharged.
The process may be repeated until all of the stages of the
multi-stage perforating gun 46 have been discharged.
[0028] Typically, once all of the stages of the multi-stage
perforating gun 46 have been discharged the setting tool 42 and the
now discharged multi-stage perforating gun 46 are raised to the
surface 20. A new or rebuilt bottom hole assembly 40 may then be
pumped back down through the casing 14. As the bottom hole assembly
40 is pumped down the casing any fluid in the casing is pushed
ahead of the bottom hole assembly 40 and out of the casing 14
through the ports 52 and into the formation 12.
[0029] Usually upon completion of the perforating and fracturing
operations the operator will pull the last multi-stage perforating
gun 46 and the setting tool 44 out of the casing 14. However, the
well cannot be produced as in inflow of fluids including
hydrocarbons from the formation 12 through ports 52 into the casing
14 and to the surface is blocked by the packers 42 that remain in
well and block fluid flow in both directions. The operator will
typically run back into the casing with a drill or mill and proceed
to drill out each of the individual packers 42 that remain in the
well and block fluid flow to the surface. Such an operation takes
time and is correspondingly expensive.
[0030] FIG. 2 depicts the packer 42 described above is replaced
with an embodiment of the current invention. The bottom hole
assembly described above has a packer 100. The packer 100 has a
mandrel 102. The mandrel 102 has an interior bore 150 extending the
length of the mandrel 102. In the interior bore 150 of the mandrel
102 is a one way valve 160. The one way valve may be a flapper type
valve having a seat 162, a flapper 164, and a bias device such as a
spring 166. Typically the spring 166 will bias the flapper 164 in a
closed condition so that any fluid from above the one way valve 160
will not be allowed to pass through the interior 150 of the packer
100 once the packer 100 is set.
[0031] At the lower end of the mandrel 100 is an angled mule shoe
104 that may be secured to the mandrel 102 by pins 106, in some
instance the muleshoe 106 may be secured by adhesives or may be
manufactured as integral to the mandrel 102. Just above the
muleshoe 106 is a slip 110. The slip 110 has an angled inner
surface 112 that cooperates with the angled exterior surface 114 of
the slip wedge 116. The slip 110 has gripping teeth 120 to bite
into or otherwise grip the casing 14. The gripping teeth 120 may be
buttons as shown or may be integral to the slip 110. The slip 110
may be a frangible solid or it could be made of a multitude of
individual segments. Typically just above the slip wedge 116 is a
sealing element 122. The sealing element 122 may be an elastomer or
any other material that may be relatively easily deformed. Above
the sealing element 122 may be a second slip wedge 124. The second
sip wedge 124 has an angled exterior surface 126 that cooperates
with the angled inner surface 130 of the second slip 132. The
second slip 132 has gripping teeth 134 to bite into or otherwise
grip the casing 14. The gripping teeth 134 may be buttons as shown
or may be integral to the second slip 132. The second slip 132 may
be a frangible solid or it could be made of a multitude of
individual segments. Above the second slip 132 may be a push ring
136.
[0032] Each of the slip 110, the slip wedge 116, the sealing
element 122, the second slip wedge 124, the second slip, and the
push ring 136 are slidably mounted on the mandrel 102.
[0033] When the packer 100 is in position the setting tool is
secured to the mandrel 100 and applies force in the direction of
arrow 140 to the push ring 136. As the push ring 136 is forced
downwards along the mandrel 102 each of the slidably mounted
components are also moved longitudinally downwards. The second slip
132 is pushed towards the second slip wedge 124 so that the angled
exterior surface 126 that cooperates with the angled inner surface
130 of the second slip 132 force the second slip 132 to move
radially outwards causing the gripping teeth 134 to bite into the
casing 14. The slip 110 is pushed towards the slip wedge 116 so
that the angled exterior surface 114 cooperates with the angled
inner surface 112 of the slip 110 to force the slip 110 to move
radially outwards causing the gripping teeth 120 to bite into the
casing 14. At the same time as the sealing element 122 is
longitudinally compressed it is force to expand radially outwards
to seal against both the mandrel 102 and the casing 14 sealing the
exterior of the mandrel 102 to fluid flow in either direction.
[0034] While one embodiment of a packer, a double slip type, is
depicted the invention may be utilized with any style packer.
[0035] FIG. 3 depicts a packer 200 having ball type one way valve
168. A ball 170 may land on the seat 172 which may be attached to
the mandrel by screws, pins, adhesives, manufactured as integral to
the mandrel 102 or otherwise fixed in place in the interior 150 of
the mandrel 102 by known means. A pin 174 or other restraining
device will trap the ball 170 in the vicinity of the seat when
fluid flows from the bottom of the packer 100 towards the top of
the packer such as when the packer 100 is being run into the casing
14 or when the well is put on production and fluid flows from the
formation through the ports 52 into the casing 14 and to the
surface 20. However when fluid flows from the surface 20 towards
the bottom of the casing 14 such as when the formation is being
fractured the ball 170 will land on the seat 172 to prevent any
flow through the interior 150 of the mandrel 102.
[0036] FIG. 4 depicts the packer 100 of FIG. 2 with a one way
flapper type valve 160 as it erodes or degrades in the casing 14.
Typically after the formations 12 have been treated or fractured
the well may be put on production utilizing a one way valve 160 to
allow the formation fluid to flow through the ports 12 into the
casing 14, through the one way valve 160 in packer 100 and then to
the surface 20. While the one way valve 160 allows the well to be
put on production quickly many operators prefer the full bore of
the interior, diameter 202 of the casing 14 to be utilized when the
well is on production in order to maximize fluid flow from the
formation 12 to the surface 20. Previously the operator would have
had to mill or drill the packers 100 out of the casing 14 in order
to allow full bore, diameter 202, access to the formation 20. In
the embodiment depicted in FIG. 4 the packer may be at least
partially constructed of an erodible material, such as ployglycolic
acid, although any material that is biodegradable, erodes over
time, or in the presence of an activating chemical or enzyme, such
as a hydrocarbon could be utilized. In certain instances it may be
desirable to at least partially construct a packer 100 using a
mixture of the erodible material, such as polyglycolic acid, with
another material that may not be erodible. For instance,
polyglycolic acid could be mixed with polylactic acid or other
polymers. Additionally, the erodible material could be utilized as
a binder in combination with a fiber such as carbon fiber or glass
fiber to create an erodible composite packer. The erodible material
may not be utilized to create the entire packer but it could be
used to create most portions of the packer depending upon the
relative strength of the materials required. When mixed with the
appropriate elastomer or polymer the erodible material could be
used as the sealing element 122. An extensive use of erodible
material would allow the formation fluid 206 to erode the packer
100 as they pass through the packer 100 forming eddy currents 204
accelerating the erosion of the packer 100 and thereafter carry the
pieces of the packer 100 to the surface 20.
[0037] Bottom, lower, or downward denotes the end of the well or
device away from the surface, including movement away from the
surface. Top, upwards, raised, or higher denotes the end of the
well or the device towards the surface, including movement towards
the surface. While the embodiments are described with reference to
various implementations and exploitations, it will be understood
that these embodiments are illustrative and that the scope of the
inventive subject matter is not limited to them. Many variations,
modifications, additions and improvements are possible.
[0038] Plural instances may be provided for components, operations
or structures described herein as a single instance. In general,
structures and functionality presented as separate components in
the exemplary configurations may be implemented as a combined
structure or component. Similarly, structures and functionality
presented as a single component may be implemented as separate
components. These and other variations, modifications, additions,
and improvements may fall within the scope of the inventive subject
matter.
* * * * *