U.S. patent application number 11/642230 was filed with the patent office on 2007-07-05 for concentric coiled tubing annular fracturing string.
Invention is credited to Mitch Lambert, Chad Northeast, John Edward Ravensbergen.
Application Number | 20070151735 11/642230 |
Document ID | / |
Family ID | 37964330 |
Filed Date | 2007-07-05 |
United States Patent
Application |
20070151735 |
Kind Code |
A1 |
Ravensbergen; John Edward ;
et al. |
July 5, 2007 |
Concentric coiled tubing annular fracturing string
Abstract
An improved concentric coiled tubing annular fracturing string
is disclosed having at least two fluid flow paths. An umbilical
tube located inside of a coiled tubing string may provide one of
the pathways, which may be used to isolate downhole elements, such
as a packer, from harmful fluids. The annulus between the umbilical
tube and the outer coiled tubing may provide the second flow
pathway. The umbilical tube may contain an electric line, which may
provide an electrical connection to a bottom hole assembly ("BHA").
The improved system may also provide for the measurement of down
hole fracturing fluid pressure or be used to deliver a
cross-linking agent to a specified portion of a well. The BHA may
include an emergency packer deflation device to rapidly deflate a
packer in the event the packer loses its ability to anchor against
the casing.
Inventors: |
Ravensbergen; John Edward;
(DeWinton, CA) ; Lambert; Mitch; (Calgary, CA)
; Northeast; Chad; (Calgary, CA) |
Correspondence
Address: |
HOWREY LLP
C/O IP DOCKETING DEPARTMENT
2941 FAIRVIEW PARK DRIVE, SUITE 200
FALLS CHURCH
VA
22042-7195
US
|
Family ID: |
37964330 |
Appl. No.: |
11/642230 |
Filed: |
December 20, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60753295 |
Dec 21, 2005 |
|
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|
Current U.S.
Class: |
166/308.1 ;
166/177.5; 166/187 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 33/127 20130101; E21B 17/203 20130101; E21B 17/206
20130101 |
Class at
Publication: |
166/308.1 ;
166/177.5; 166/187 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A coiled tubing annular fracturing string, the string
comprising: a coiled tubing string; a bottom hole assembly
including an inflatable packing element, the bottom hole assembly
connected to the coiled tubing string; and an umbilical tube
located within the coiled tubing string, wherein the umbilical may
be used to inflate or deflate the inflatable packing element.
2. The string of claim 1 wherein the bottom hole assembly further
includes an anchor.
3. The string of claim 2 wherein the umbilical tube may be used to
set or release the anchor within a wellbore.
4. The string of claim 1 wherein the inflatable packing element
anchors the bottom hole assembly against a casing of a wellbore
when inflated.
5. The string of claim 1 further comprising an emergency deflation
device in communication with the packing element, wherein the
packing element is deflated if the inflated packing element is no
longer anchored against the casing.
6. The string of claim 5 the emergency deflation device includes a
piston rod, a piston, and a spring.
7. The string of claim 6 wherein the emergency deflation device is
adapted to equalize the pressure across the inflated packing
element.
8. The string of claim 1 further comprising an electric wireline
located within the umbilical tube.
9. The string of claim 8 wherein the electric wireline allows
communication between the surface and an element of the bottom hole
assembly.
10. The string of claim 9 wherein the element is a set of
perforating guns, a pressure transducer, a temperature gauge, or a
casing collar locator.
11. The string of claim 1 further comprising one or more fluid
ports located above the packing element.
12. The string of claim 11 wherein the coiled tubing string
delivers wash fluids or circulating fluids through the one or more
fluid ports to a location within the wellbore.
13. The string of claim 1 wherein the one or more fluid ports
include a one way valve.
14. The string of claim 1 wherein a negative pressure is applied to
the packing element through the umbilical tube to deflate the
packing element.
15. The string of claim 1 further comprising a second umbilical
tube located within the coiled tubing string, wherein the second
umbilical provides a third fluid flow path.
16. The string of claim 15 wherein the second umbilical does not
extend the entire length of the coiled tubing string.
17. The string of claim 1 wherein the umbilical tube delivers a low
specific gravity fluid to the packing element.
18. A coiled tubing string for use in the annular coil tubing
fracturing, the coiled tubing string comprising: a bottom hole
assembly, the bottom hole assembly including an inflatable packing
element; a first fluid flow path, wherein the first fluid flow path
may be used to deliver fluid to a desire downhole location within a
wellbore; and a second fluid flow path, wherein the second fluid
flow path may deliver fluid to inflate or deflate the inflatable
packing element.
19. The coiled tubing string of claim 18 further comprising an
electric wireline located within the second fluid flow path.
20. The coiled tubing string of claim 18 further comprising at
least one fluid port in communication with the first fluid flow
path.
21. The coiled tubing string of claim 20 further comprising an one
way valve preventing two way flow through the at least one fluid
port.
22. A coiled tubing string, the coiled tubing string comprising: a
first fluid flow path within the coiled tubing string; a second
fluid flow path within the coiled tubing string; a bottom hole
assembly, the bottom hole assembly including a hydraulically set
anchor and an inflatable packing element; means for requiring a
first predetermined pressure within the second flow path before the
anchor is set; and means for requiring a second predetermined
pressure within the second flow path before the packing element
begins to inflate.
23. The coiled tubing string of claim 22 further comprising means
for ensuring that the anchor is set prior to beginning to inflate
the packing element and means for ensuring that the packing element
deflates prior to unsetting the anchor.
24. The coiled tubing string of claim 22 further comprising means
for preventing the over inflation of the packing element.
25. The coiled tubing string of claim 24 further comprising means
for ensuring that the pressure within the packing element is
greater than the pressure of a fracturing zone within a
wellbore.
26. The coiled tubing string of claim 22 further comprising means
for ensuring that the pressure within the anchor is greater than
the pressure within the packing element.
27. The coiled tubing string of claim 22 wherein the second fluid
flow path protects the packing element from harmful fluids present
in the first fluid flow path.
28. The coiled tubing string of claim 22 wherein the second fluid
flow path contains a low specific gravity fluid.
29. A coiled tubing string, the coiled tubing string comprising: a
first fluid flow path within the coiled tubing string; a second
fluid flow path within the coiled tubing string; a bottom hole
assembly, the bottom hole assembly including an inflatable packing
element; a pressure relief valve, the pressure relief being in
communication with the second fluid flow path and the packing
element, wherein the pressure relief valve is biased to a closed
position preventing the inflation of the packing element; and a
check valve, the check valve parallel with the pressure relief
valve being in fluid communication with the second fluid flow path
and the packing element.
30. The coiled tubing of claim 29 wherein the pressure relief valve
requires a predetermined amount of pressure to be within the second
fluid flow path before the pressure relief valve opens.
31. The coiled tubing of claim 30 wherein the second fluid flow
path contains a low specific gravity fluid.
32. A emergency deflation device for a coiled tubing string, the
device comprising: a housing connected above an inflatable packing
element, the packing element being able to anchor against a casing
when inflated with fluid; a chamber within the housing, the chamber
being in fluid communication with the packing element; a piston and
a piston rod positioned within the chamber; at least one shearable
element, the shearable element selectively securing the housing to
the piston rod; wherein if the packing element loses the ability to
anchor against the casing the load on the packing element shears
the at least one shearable element releasing the housing from the
piston rod; and wherein the housing and packing element moves away
from the piston rod causing the piston to stroke within the chamber
drawing the fluid out of the packing element.
33. The emergency deflation device of claim 32 further comprising a
crush ring, wherein the crush ring prevents damage to the
piston.
34. The emergency deflation device of claim 32 wherein the housing
is adapted to equalize the pressure above and below the packing
element and the piston has been stroked within the chamber.
35. A method of fracturing a perforated zone of a wellbore with a
coiled tubing string having at least two flow paths, the method
comprising: pumping a first fluid down a first flow path of a
coiled tubing string to inflate a packing element to isolate a zone
of a wellbore; pumping fracturing fluid down the annulus between
the coiled tubing string and the wellbore; pumping a fluid down the
second flow path of the coiled tubing string, the fluid being a
wash fluid; and circulating the wash fluid to the perforating zone
through one or more fluid ports in the coiled tubing string.
36. The method of claim 35 further comprising applying a negative
pressure within the first flow path of the coiled tubing string to
deflate the packing element.
37. The method of claim 35 wherein the first fluid is a low
specific gravity fluid.
38. The method of claim 35 further comprising communicating with a
downhole element connected to the coiled tubing string to determine
the temperature, pressure, or location of the fracturing zone.
39. The method of claim 38 wherein an electrical wireline located
within the first flow path is used to communicate with the downhole
element.
40. The method of claim 35 further comprises pumping the first
fluid down the first flow path of the coiled tubing string to set
an anchor.
41. The method of claim 35 wherein the inflated packing element
anchors the coiled tubing string to casing of the wellbore.
42. The method of claim 35 further comprising pumping a
cross-linking agent down the second flow path of the coiled tubing
string.
43. The method of claim 42 further comprising circulating the
cross-linking agent through the one or more fluid ports in the
coiled tubing string.
44. The method of claim 35 further comprising pumping a fluid down
the second flow path and circulating the fluid out of the one or
more fluid ports to determine the fluid pressure of the zone of the
wellbore, wherein the fluid is slowly pumped down the second flow
path.
45. The method claim 35 further comprising pumping a fluid down a
second flow path of the coiled tubing string, the second fluid
being acid.
46. The method claim 45 further comprising circulating the acid to
the perforating zone through one or more fluid ports in the coiled
tubing string.
47. A method of fracturing the formation of a perforated zone of a
wellbore with a coiled tubing string having a first flow path and a
second flow path, the method comprising: pumping a first fluid down
the first flow path to inflate a packing element to isolate a zone
of a wellbore; pumping fracturing fluid down the annulus between
the coiled tubing string and the wellbore after the zone of the
wellbore has been isolated, wherein the fracturing fluid is pumped
down the annulus until the formation is fractured; pumping a fluid
down the second flow path of the coiled tubing string while the
fracturing fluid is pumped down the annulus, wherein the fluid
includes a cross-linking agent; and circulating the fluid that
includes the cross-linking agent to the perforating zone through
one or more ports in the coiled tubing string while the fracturing
fluid is pumped down the annulus.
48. The method of claim 47 further comprising pumping wash fluid
down the second flow path after the fracturing fluid is no longer
pumped down the annulus and circulating the wash fluid to the
perforating zone through the one or more ports in the coiled tubing
string.
49. The method of claim 47 further comprising pumping acid down the
second flow path and circulating the acid to the perforating zone
prior to pumping fracturing fluid down the annulus.
50. The method of claim 47 further comprising applying a negative
pressure within the first flow path of the coiled tubing string to
deflate the packing element after circulating wash fluid to the
perforating zone.
51. A method of fracturing a perforated zone of a wellbore with a
coiled tubing string having at least two flow paths, the method
comprising pumping a first fluid down a first flow path to inflate
a packing element to isolate a zone of a wellbore; pumping
fracturing fluid down the annulus between the coiled tubing string
and the wellbore after the zone of the wellbore has been isolated,
wherein the fracturing fluid is pumped down the annulus until the
formation is fractured; pumping a fluid down a second flow path of
the coiled tubing string while the fracturing fluid is pumped down
the annulus, wherein the fluid is a wash fluid; and circulating the
wash fluid to the perforating zone through one or more ports in the
coiled tubing string while the fracturing fluid is pumped down the
annulus.
52. A method of fracturing a perforated zone of a wellbore with a
coiled tubing string, the method comprising: setting a packing
element to isolate the perforated zone of the wellbore; pumping
fracturing fluid down the annulus between the coiled tubing string
and the wellbore; pumping a fluid down the coiled tubing string,
the fluid being a wash fluid; and circulating the wash fluid to the
perforating zone through one or more fluid ports in the coiled
tubing string.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application is a Non-provisional application claiming
benefit of U.S. Provisional Application Ser. No. 60/753,295,
entitled, "Concentric Coiled Tubing Annular Fracturing String," by
John Edward Ravensbergen, Mitch Lambert, and Chad Northeast, filed
Dec. 21, 2005, hereby incorporated by reference in its entirety
herein.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates generally to an improved
coiled tubing annular fracturing string and bottom hole assembly
("BHA"). The improved string includes an umbilical tube located
inside a coiled tubing string connected to a BHA. The umbilical
tube may be used, for example, to inflate or deflate a packer or
used to activate a hydraulic set anchor. The invention is
particularly useful in fracturing oil and gas wells with coiled
tubing.
[0004] 2. Description of the Related Art
[0005] U.S. Pat. Nos. 6,520,255 and 6,394,184 disclose a method of
fracturing an oil/gas well, named the Annular Coil Tubing
Fracturing Process, or the ACT-Frac Process for short. The ACT-Frac
Process, and the corresponding bottom hole assembly ("BHA") allows
for the perforation and fracture of multiple zones downhole during
a single trip of the BHA. The BHA disclosed in these patents is
comprised of a number of components including an anchor, a packer,
and multiple perforating guns. As the name of the process implies,
the BHA is connected to the surface by a coiled tubing string.
[0006] In the ACT-Frac Process, the BHA is lowered into the casing
of the oil/gas well with the coiled tubing. An electric wireline is
located inside a coiled tubing string. The BHA includes an
electrical casing collar locator ("CCL"), which is connected to the
wireline and may be used to accurately position the BHA in the
wellbore. A number of commercially available CCLs known to one of
ordinary skill in the art may be used. The CCL is used to locate
the first fracturing zone (i.e., lowermost) to be perforated and
the perforating guns of the BHA are positioned within the first
fracturing zone. After being properly positioned within the first
fracturing zone, one of the perforating guns is discharged and the
zone is perforated.
[0007] After perforating the fracturing zone, the BHA is lowered
beneath the fracturing zone and the anchor is mechanically set
against the casing. Fluid is then pumped down the coiled tubing
string to inflate the packer until it is secure against the casing.
Both the packer and the anchor, which is located below the packer,
are set beneath the perforations. Once the packer and the anchor
are set, fracturing fluid is pumped down the annulus between the
coiled tubing string and the casing and into the perforations. The
packer isolates the wellbore beneath the packer from the fracturing
pressure.
[0008] After fracturing the zone, the packer is then deflated, the
anchor is released, and the BHA is moved through the fracturing
fluid/slurry that remains in the central bore. Washing fluid can
also be pumped down the coiled tubing string and out one or more
circulating ports located above the packer to wash any remaining
fracturing fluid or fracturing slurry away from the packer and the
BHA. The BHA is then positioned such that the perforating guns are
located in the next fracturing zone (above the previously fractured
zone) to be perforated and the process is repeated.
[0009] A simpler alternative configuration of a BHA used in the
ACT-Frac Process may include an inflatable packer without an
anchor. Instead, the inflatable packer is used to both isolate the
zone and anchor the BHA against the casing. The packer is inflated
against the casing and may be required to hold a pressure
differential from above to below the packer of up to 7000 psi. One
vital characteristic of the inflatable packer used in this BHA is
its ability to anchor itself using the friction force between the
inflated packer and the casing, which typically will be sufficient
if the pressure within an inflated packer is greater than the
pressure above the packer. However, if the pressure drop across the
packer is large and the pressure above the packer becomes the same
as the pressure inside the inflated packer, the packer will lose
its ability to anchor against the casing. In this instance, the
force generated by the pressure drop across the packer is now only
resisted by the coiled tubing string.
[0010] The failure of the inflated packer to remain anchored
presents a serious problem if the pressure drop across the packer
is large as would be appreciated by one of ordinary skill in the
art having the benefit of this disclosure. A typical 13/4 inch
coiled tubing string at a depth of 13,000 feet can typically handle
a maximum overpull of 25,000 lbs. If a force of 25,000 lbs. or more
is exerted on the coiled tubing string the coiled tubing string may
either break or activate an emergency release sub. In either event,
the BHA will be dropped into the wellbore, which may require an
expensive fishing job to remove the BHA from the wellbore. Fishing
for live perforating guns may increase the cost of fishing the BHA
due to regulatory pressures. If the packer loses its ability to
anchor, a relatively small pressure drop from above to below the
packer can create a force of 25,000 lbs. For example, in a 41/2
inch casing, a pressure drop of approximately 2,000 psi across the
packer will generate a 25,000 lbs. force on the coiled tubing
string in the instance that the packer loses its ability to anchor.
As the diameter of the casing increases, a smaller pressure drop is
required to produce the same amount of force on the coiled tubing
string. For example, in a 7 inch casing a pressure drop of
approximately 800 psi across the packer may create a 25,000 lbs.
force in the event the packer loses its ability to anchor.
[0011] There are two instances when the pressure above the packer
becomes the same as the pressure inside of the packer. One such
instance is when the pressure inside the packer is reduced. The
pressure in the packer can decrease if fluid is removed from inside
the packer during the deflation process or if the packer fails,
allowing fluid to exit the packer into the wellbore below the
packer.
[0012] If the packer is deflated when the pressure drop across the
packer is small, the deflation process is done in a controlled and
safe manner as the pressure induced load on the BHA is less than
the force required to shear the emergency release tool or break the
CT string. However, under some circumstances the pressure drop
across the packer is not known before the deflation process begins.
In addition, it may be advantageous to hold up to 500 psi pressure
differential across the packer during the deflation of the packer
to fluidize the proppant that has settled on the packer when the
packer is deflated.
[0013] The packer has the highest probability of failing when the
pressure differential across the packer is high, and as a result
the pressure inside the packer is high. When the pressure
differential across the packer is large the forces imparted on the
BHA are large. Therefore, there is a high probability that if the
packer fails the forces will be large and the emergency release
tool may activate or the CT string may break.
[0014] The other such instance of when the pressure above the
packer becomes the same as the pressure inside of the packer is
when the pressure above the packer, which is the fracturing
pressure, increases to the pressure within the packer. The
fracturing pressure can rise quickly and unexpectedly during a
screen out, also referred to as a sand off. As discussed above, the
pressure drop across the packer can be as much as 7000 psi during
the fracturing process, but the pressures can exceed 7000 psi if a
screen out occurs. The screen out pressure is often above the
pressure rating of the packer, which may cause the packer to fail.
If the packer were to lose its ability to anchor while experiencing
such a high pressure drop, the forces generated by the pressure
drop may be too massive for the coiled tubing string to withstand,
thus breaking the coiled tubing string or releasing an emergency
release sub in the BHA. In the event this occurs, live perforation
guns may be dropped into the wellbore requiring a later retrieval
or discharge of the perforation guns.
[0015] As is discussed above, the coiled tubing string has two
prime hydraulic functions. Namely, to deliver fluids to set and
unset the packer as well as to deliver fluids to one or more wash
ports in an attempt to remove any residual fracturing fluid or
slurry. The ACT-Frac Process may have certain disadvantages or
potential issues. Many of these disadvantages or potential issues
are due to the two hydraulic functions, but only one flow path,
i.e. the coiled tubing string.
[0016] One potential issue deals with the hydraulic valves used to
switch between delivering fluid to inflate the packer and
delivering wash fluid to the ports to remove excess fracturing
fluid/slurry. Hydraulic valves have moving parts with small
clearances between the moving parts relative to the size of a
particle or mill scale typically found in a coiled tubing string.
The use of such valves requires the careful filtering of the fluids
at both the surface and at the BHA to minimize the risk of damaging
or fouling the valve mechanisms.
[0017] The use of hydraulic valves to switch between hydraulic
functions of the coiled tubing string also adds complexity to the
BHA. The complexity of the BHA may increase the cost to purchase
and to maintain the BHA. Additionally, the presence of the valves
requires a highly trained staff to maintain and operate the BHA.
Over time the valves may not function properly due to repeated use
and also being repeatedly subjected to harsh and damaging
chemicals.
[0018] Acid and/or inhibited acid may be pumped through the coiled
tubing string to stimulate the formation before each fracturing
stimulation. Inhibitors in the acid are harmful to the mechanisms
in the hydraulic valves and may increase the likelihood of valve
failure. Acid is harmful to metal used in the BHA and/or coiled
tubing string. The use of inhibitors often creates a coating on the
metal in an effort to protect it from the acid, but this coating
may seep into the valves potentially causing the valves to
malfunction. Additionally, chemically corrosive fluids, such as
fluids containing nitrogen, used for stimulation, treatment, or
washing of the BHA may be pumped downhole through the coiled tubing
string. These fluids can chemically attack the rubber used to
manufacture the packer, compromising the packer's ability to
repeatedly hold high pressure at downhole temperatures. The
chemicals pumped down the coiled tubing string may also be
corrosive to the electric wireline located inside the coiled tubing
string used to communicate electrically to the BHA.
[0019] The fact that the coiled tubing string has two hydraulic
functions, but only one fluid path presents another potential
problem. When fracturing a perforated zone fracturing fluid is
pumped down the annulus between the casing and the coiled tubing
string while fluid is pumped down the coiled tubing string to
inflate and set the packer against the casing holding the BHA in
place. However the one fluid flow path may be a problem if
circulating fluid needs to be pumped down the coiled tubing string
to the fracturing zone. The original process was not designed to
handle pumping circulating fluid in a timely manner. Instead, the
circulating ports must first be activated by switching the valves
in the BHA from the packer to the circulating ports. Additionally,
the fluid source for the pump needs to be switched between the
fluid used to inflate the packer and the circulating fluid.
Alternatively, a second pump attached to the circulating fluid may
be used, but this requires hydraulically connecting the second pump
to the coiled tubing string. In any case, if a problem with the
fracturing fluid arises the original design does not provide an
apparent rapid solution.
[0020] Another potential problem of the coiled tubing string and
BHA design may arise in the event that the packer fails. The prior
design of the BHA used in the ACT-Frac Process does not provide a
flapper valves or valve protection against fluid flow up the coiled
tubing string. Thus if the packer were to fail, hydrocarbons
present in the well may flow up through the coiled tubing string to
the surface.
[0021] As is discussed above, prior designs disclose using a
mechanically set anchor below the packer. One potential problem
with a mechanically set anchor is that the setting mechanism may
become damaged or fouled when dirty fluids are present in the well
annulus. In addition, while setting an inflatable packer, large
additional setting forces can be imparted to the anchor. Theses
forces may become large enough that it is no longer possible to
release the anchor with the CT string. Additionally, the
substantial change in shape of the inflatable packer from its
deflated state to its final inflated set state may impart loads
into the packer mandrel and subsequently into the anchor while the
packer is set. The location of the anchor below the packer may lead
to the buckling of the packer mandrel for packer designs in 41/2
inch casings or smaller due to the loads imparted from the setting
of the packer.
[0022] Another problem with current fracturing methods is the
failure to know the downhole pressure of fracturing fluid at all
times during the fracturing process. It is useful to monitor the
downhole pressure of the fracturing fluid in real time in order to
better manage the fracturing process. When fracturing a well the
fluid pressure of the fracturing fluid causes a crack or a fracture
in the formation to propagate. Proppant in the fracturing fluid
holds the fracture open after the fracturing fluid exits the crack.
However, too much proppant at the leading edge of the fracture may
create a sand-out. A sand-out occurs when the proppant, which is
often sand, reaches the leading edge of the fracture thereby not
allowing enough fluid flow to continue to propagate the fracture in
the formation. The downhole fluid pressure of the fracturing fluid
is rather difficult to determine because the composition of the
fracturing fluid changes throughout the process as the amount of
proppant is increased over the duration of the process, thus
changing the density of the fracturing fluid. The changing density
as well as frictional pressure drop as the fracturing fluid travels
down the annulus makes it difficult to determine the bottom hole
pressure of the fracturing fluid.
[0023] Another problem with accurately determining the pressure at
the perforation tunnel is the fracturing fluid can be designed to
cross-link as it moves downhole thus, thickening the fluid.
Ideally, the fracturing fluid becomes fully cross-linked just as it
reaches the perforated formation in the well. The viscosity of the
fluid increases as it becomes more cross-linked. The changing
viscosity makes it difficult to calculate the frictional pressure
drop of the fracturing fluid, thereby making it difficult to
calculate the bottom hole pressure of the fracturing fluid.
[0024] Another problem relates to the use of inflatable packers
comprised of synthetic rubber. Synthetic rubber is used because it
is more chemically resistant than natural rubber to hydrocarbon
fluids. The packer is one of the most expensive components of the
BHA, as a new packer typically is required for each trip of the BHA
into the well casing. The use of an inflatable packer may present a
problem in the removal of a BHA from the well casing. Generally a
packer will deflate to a size that is larger in diameter than its
original size (e.g., 1/2 inch larger in diameter) once it has been
inflated and set against the casing. This presents a serious
problem as the packer may not allow or make it more difficult for
the proppant to flow past the packer after deflation and thereby
causing the BHA to become stuck downhole.
[0025] In light of the foregoing, it may be desirable to provide an
emergency packer deflation device that may rapidly remove the fluid
from an inflated packer in the event the packer loses its ability
to anchor against the casing. By removing the fluid from the
packer, the packer rapidly deflates and the coiled tubing string
will not be subjected to a large force due to a pressure drop
across the packer. It may further be desirable to provide an
emergency packer deflation device that is adapted to equalize the
pressure across the packer.
[0026] It may be desirable to provide a coiled tubing string that
does not have one fluid flow path for two hydraulic functions. It
may also be desirable to provide a coiled tubing string that does
not use valves to switch between hydraulic functions. Further, it
may be desirable to provide a coiled tubing string that has
separate fluid paths to eliminate potential problems caused by
corrosive chemicals pumped down to the BHA. It may be desirable for
a coiled tubing string to be able to pump down fluid to circulate
downhole fracturing fluid while also pumping fluid in a separate
fluid path that keeps a packer inflated and/or an anchor set
against a well casing. It may also be desirable to provide a coiled
tubing string that allows for the monitoring of hydrostatic
pressure or downhole temperature at the perforation tunnel.
Additionally, it may be desirable for a coiled tubing string to
provide for the injection of a cross-linking catalyst at the
fracturing zone. It may also be desirable for a coiled tubing
string that provides negative pressure to a packer to ensure that
the packer deflates to substantially its original dimensions. It
may further be desirable for the BHA to include a hydraulically set
anchor located above of the packer for 41/2 inch diameter and
smaller casing sizes. Finally, it may be desirable for the BHA to
include flapper valves to prevent the flow of well fluid up the
coiled tubing string even if the packer was to fail.
[0027] The present invention is directed to overcoming, or at least
reducing the effects of, one or more of the issues set forth
above.
SUMMARY OF THE INVENTION
[0028] The present application discloses an improved annular coiled
tubing fracturing system that provides separate fluid paths to the
BHA for at least two different hydraulic functions. In one
embodiment, this is achieved by installing an umbilical tube inside
the coiled tubing string. Preferably, the umbilical tube is a
coiled tubing string with a smaller diameter inserted inside a
large coiled tubing string ("the CT string"). Preferably, the
umbilical tube and the CT string create a concentric coiled tubing
string. The umbilical tube may be used to deliver fluid to inflate
a packer and/or to activate a hydraulic set anchor. The umbilical
tube may also provide the fluid path for the release of fluids to
deflate the packer and/or deactivate the hydraulic set anchor. The
umbilical tube can also be used in a conduit for the electric
wireline to protect it from corrosive fluids pumped down the CT
string. The CT string may be used to deliver different fluids to
fluidize settled proppant, and/or wash proppant out of the wellbore
between fracturing procedures. Alternatively, the umbilical tube
may be used to deliver fluids to fluidize settled proppant and/or
wash proppant while the CT string may be used to deliver fluid to
inflate a packer and/or to activate a hydraulic set anchor.
[0029] In one embodiment, the CT string may be attached to a BHA
with at least one fluid port located near the top of the packer. In
one embodiment, the at least one fluid port may include a one way
valve, such as a flapper valve for example, to prevent fluid in the
well from flowing up the CT string.
[0030] The umbilical tube may be connected to a packer element of
the BHA and may provide a fluid path to inflate or deflate the
packer. The umbilical tube may additionally be connected to a
hydraulically actuated anchor and provide a fluid path to activate
or deactivate the anchor.
[0031] In one embodiment an electric line or a wireline may be run
downhole inside the umbilical tube. The electric line may be
electrically connected to various elements in the BHA. The electric
line may be encased by a number of steel cables, which both protect
the electric line as well as provide the requisite strength to the
line. The umbilical tube may be used to protect the wireline from
acid, as wirelines are often made from galvanized extra plow steel,
which is suscepible to corrosive attack from acids.
[0032] The use of an umbilical inside the CT string provides two
fluid flow paths allowing for the use of different fluids.
Specifically, the two fluid paths allow the use of a washing fluid
and a different less corrosive fluid to control the packer and/or
anchor. In one embodiment, the umbilical may be corrosion free
tubing, such as stainless steel tubing, and may deliver clean
fluids to the packer, anchor or both. The two fluid flow paths
allows for the circulation of fracturing fluid while a different
fluid is pumped down the umbilical tube to inflate the packer, if
needed.
[0033] In one embodiment, a fluid with a specific gravity lower
than water may be used in the umbilical. A low specific gravity
umbilical fluid is useful to create a hydrostatic pressure in the
BHA that is less than the hydrostatic pressure in the wellbore when
the BHA is in the wellbore at typical fracturing depths. A
relatively low pressure in the BHA, with respect to the wellbore
pressure, may be useful in forcing the packer to completely deflate
and return to its original shape. A relatively low pressure in the
BHA, with respect to the wellbore pressure, may also be useful to
force the buttons of a hydrostatic set anchor to completely
retract. A completely deflated packer and completely retracted
buttons may decrease the chance that the BHA becomes stuck in the
wellbore. An example of a suitable low specific gravity fluid is
Petro-Canada's HT 40N drilling mud, which is a clear fluid with a
specific gravity of 0.83. Additionally, Petro-Canada's HT 40N
drilling mud also has a high aniline number and therefore is not
chemically aggressive toward synthetic rubber. The use of fluid
with a low freezing temperature in the umbilical may allow
operation in the winter when temperatures drop below the freezing
point of water based fluids. The use of other fluids, such as
methanol/water acid, that do not harm the rubber in a natural
rubber packer may allow the repeated use of the same packer in
subsequent downhole trips removing a considerable expense of such
operations.
[0034] Explosive decompression occurs in rubber when exposed to
high pressure gas. The use of an umbilical may prevent exposure of
the rubber in the packer to high pressure gas. Wash fluid is often
water or a water based fluid mixed with nitrogen gas, as it is an
ideal, low cost fluid for performing clean up operations. However,
fluids containing nitrogen may damage the rubber used to construct
inflatable packers. The umbilical tube may be used to eliminate
exposure to nitrogen gas on the inside of the packer.
[0035] As discussed above, a serious problem occurs if the packer
becomes stuck downhole. In one embodiment, a special fluid may be
pumped down the umbilical tube and/or the CT string in an effort to
help dislodge the packer. The fluid may contain a chemical, such as
xylene, that attacks or weakens the rubber elements in the packer.
After weakening the rubber elements, the packer may then be able to
be removed from the wellbore.
[0036] In one embodiment, the CT string may be used to deliver a
cross-linking catalyst to the fracturing fluid to cross-link the
fracturing fluids at the perforations, just before the fracturing
fluid slurry enters the formation. The cross-linking agent may be
pumped down the CT string and enter the casing at the fracturing
zone, which is the portion of the wellbore directly above the
packer, via circulation ports allowing for better control of the
timing of the cross-linking, optimizing the suspension of the
proppant in the fracturing fluid.
[0037] Another improvement of the umbilical embodiment is that the
electric line in the umbilical can be used during the ACT-Frac
Process to measure the fracturing fluid pressure real time. During
the ACT-Frac Process it is difficult to know the pressure down hole
from measuring the fracturing fluid injection pressure due to the
dynamics of the pumping process and the changing properties of the
fracturing fluids. Additionally, the frictional pressure drop of
the slurry is difficult to calculate. In real time, the downhole
pressure may be measured down hole via a pressure transducer and be
communicated back to surface via the electric line.
[0038] In another embodiment, the fracturing pressure may also be
determined by measuring the injection pressure into the CT string
at surface or the injection pressure into the umbilical string at
surface. Typically the fluid properties in the CT string or the
umbilical string are not changing in time and their proprieties are
well understood. In addition, the injection rate may be low or even
static such that the frictional pressure drop may not complicate
the interpretation of the pressure down hole. Thus, it is
relatively easy to calculate the hydrostatic pressure in both the
CT string and the umbilical. The downhole pressure can be
substantially determined by slowly pumping fluid down the CT string
to where the pumped fluid very slowly exits the CT string from the
circulation ports. Because the fluid is pumped slowly, any
frictional forces may be disregarded and the downhole fracturing
fluid pressure may be approximated by adding the hydrostatic
pressure of the CT string to the pumping pressure.
[0039] Another embodiment of the present disclosure may include a
second umbilical tube in the CT string. The second umbilical may be
run the length of the CT string or alternatively be a partial
length and be used to pump a third fluid down the CT string. The
fluid pumped down the second umbilical may be nitrogen used to
chase and de-pressure at least a portion of the CT string or the
other umbilical string. The number of umbilical tubes and fluids
used in them may be varied according to BHA applications as would
be apparent to one of ordinary skill in the art having the benefit
of this disclosure.
[0040] Another embodiment of the present disclosure may include an
emergency packer deflation device that quickly draws the fluid out
of the inflatable packer once the packer loses its ability to
anchor against the casing. The emergency packer deflation device
may be connected to the BHA directly above the inflatable packer.
As discussed above, once the packer loses its ability to anchor the
pressure drop across the packer transfers a load onto the CT
string. This load may shear a set of shear pins in the emergency
packer deflation device. The pressure drop may also rapidly push
the packer downhole. The rapid movement of the packer away from the
emergency packer deflation device may stroke a piston, which may
rapidly draw the fluid out of the packer through a large area flow
path between the packer and the emergency packer deflation device.
Once the packer is deflated, the pressure drop across the packer is
greatly reduced, thus reducing the load on the CT string. Further,
the emergency packer deflation device may be adapted such that once
the piston stops moving the pressure within the emergency packer
deflation device may be equalized with the wellbore pressure. This
rapid deflation of the packer may prevent dropping the BHA into the
wellbore due to the breakage of the CT string or the releasing of
an emergency release sub.
[0041] One embodiment is a method of fracturing a perforated zone
of a wellbore with a coiled tubing string having at least two flow
paths the method includes pumping a first fluid down a first flow
path of a coiled tubing string to inflate a packing element to
isolate a zone of a wellbore and pumping fracturing fluid down the
annulus between the coiled tubing string and the wellbore. The
method includes pumping a fluid down the second flow path of the
coiled tubing string, the fluid being a wash fluid and circulating
the wash fluid to the perforating zone through one or more fluid
ports in the coiled tubing string.
[0042] The method may further include applying a negative pressure
within the first flow path of the coiled tubing string to deflate
the packing element. The application of a negative pressure may
provide that the packing element adequately deflates decreasing the
chance that the packing element may become stuck within the
wellbore. A fluid with a low specific gravity fluid may be pumped
down the first flow path to inflate the packing element.
[0043] The method may include communicating with a downhole element
connected to the coiled tubing string to determine the temperature,
pressure, or location of the fracturing zone. An electrical
wireline located within the first flow path may be used to
communicate with the downhole element. In one embodiment the method
may include pumping fluid down the first flow path of the coiled
tubing to set an anchor. Alternatively, the inflated packing
element may anchor within the wellbore. The method may include
pumping a cross-linking agent down the second flow path of the
coiled tubing string circulating the cross-linking agent through
the one or more fluid ports in the coiled tubing string. The method
may include pumping a fluid down the second flow path and
circulating the fluid out of the one or more fluid ports to
determine the fluid pressure of the zone of the wellbore, wherein
the fluid is slowly pumped down the second flow path. The method
may include pumping a fluid down a second flow path of the coiled
tubing string, the second fluid being acid and circulating the acid
to the perforating zone through one or more fluid ports in the
coiled tubing string.
[0044] Another embodiment is a method of fracturing the formation
of a perforated zone of a wellbore with a coiled tubing string
having a first flow path and a second flow path, the method
includes pumping a first fluid down the first flow path to inflate
a packing element to isolate a zone of a wellbore and pumping
fracturing fluid down the annulus between the coiled tubing string
and the wellbore after the zone of the wellbore has been isolated,
wherein the fracturing fluid is pumped down the annulus until the
formation is fractured. The method further includes pumping a fluid
that contains a cross-linking agent down the second flow path of
the coiled tubing string while the fracturing fluid is pumped down
the annulus and circulating the fluid that includes a cross-linking
agent to the perforating zone through one or more ports in the
coiled tubing string while the fracturing fluid is pumped down the
annulus. The method may include pumping wash fluid down the second
flow path after the fracturing fluid is no longer pumped down the
annulus and circulating the wash fluid to the perforating zone
through the one or more ports in the coiled tubing string.
[0045] The method may include pumping acid down the second flow
path and circulating the acid to the perforating zone prior to
pumping fracturing fluid down the annulus. The method may also
include applying a negative pressure within the first flow path of
the coiled tubing string to deflate the packing element after
circulating wash fluid to the perforating zone.
[0046] Another embodiment is a method of fracturing a perforated
zone of a wellbore with a coiled tubing string comprising setting a
packing element to isolate the perforated zone of the wellbore,
pumping fracturing fluid down the annulus between the coiled tubing
string and the wellbore, pumping a wash fluid down the coiled
tubing string, and circulating the wash fluid to the perforating
zone through one or more fluid ports in the coiled tubing
string.
[0047] Another embodiment is a method of fracturing a perforated
zone of a wellbore with a coiled tubing string having at least two
flow paths. The method includes pumping a first fluid down a first
flow path to inflate a packing element to isolate a zone of a
wellbore and pumping fracturing fluid down the annulus between the
coiled tubing string and the wellbore after the zone of the
wellbore has been isolated, the fracturing fluid being pumped until
the formation is fractured. The method further includes pumping a
wash fluid down a second flow path of the coiled tubing string
while the fracturing fluid is pumped down the annulus and
circulating the wash fluid to the perforating zone through one or
more ports in the coiled tubing string while the fracturing fluid
is pumped down the annulus.
BRIEF DESCRIPTION OF THE DRAWINGS
[0048] FIG. 1 shows the BHA used in the ACT-Frac Process.
[0049] FIG. 2 shows the BHA used in the preferred embodiment of the
present disclosure.
[0050] FIG. 3 shows a cutaway view of the present disclosure of a
CT string that includes an umbilical tube positioned inside the CT
string.
[0051] FIG. 4 is a pressure schematic of a BHA having an umbilical
connected to both a hydraulic anchor and a packer.
[0052] FIG. 5 is a pressure schematic of a BHA having an umbilical
connected directly to a packer.
[0053] FIG. 6 shows an embodiment of the present disclosure of a
BHA that includes an emergency packer deflation device.
[0054] FIG. 7 shows the packer moving away from the emergency
packer deflation device of FIG. 6.
[0055] FIG. 8 shows the removal of fluid from the packer by the
emergency packer device of FIG. 6.
[0056] FIG. 9 is cross-section view E-E of the embodiment of the
BHA of FIG. 6.
[0057] FIG. 10 shows the fluid in the packer and emergency packer
deflation device at the same pressure and in fluid communication
with the wellbore fluids.
[0058] While the invention is susceptible to various modifications
and alternative forms, specific embodiments have been shown by way
of example in the drawings and will be described in detail herein.
However, it should be understood that the invention is not intended
to be limited to the particular forms disclosed. Rather, the
intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the invention
as defined by the appended claims.
Description of Illustrative Embodiments
[0059] Illustrative embodiments of the invention are described
below as they might be employed in the use of designs for
concentric coiled tubing annular fracturing. In the interest of
clarity, not all features of an actual implementation are described
in this specification. It will of course be appreciated that in the
development of any such actual embodiment, numerous
implementation-specific decisions must be made to achieve the
developers' 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
may nevertheless be a routine undertaking for those of ordinary
skill in the art having the benefit of this disclosure.
[0060] Further aspects and advantages of the various embodiments of
the invention will become apparent from consideration of the
following description and drawings.
[0061] As shown in FIG. 1, a BHA 5 is connected to the surface via
coiled tubing 10. THE BHA 5 has circulation ports 55 and includes a
coiled tubing connector 50, a fishing sub 60, an inflatable packer
70, a mechanically set anchor 80, a CCL 90, and perforating guns
100. As discussed above, the original ACT-Frac Process required
fluid to be pumped down the coiled tubing string 10 to both wash
the packer using the circulation ports 55 and to inflate the packer
70. The BHA may be connected to an electric line that runs from the
surface down the coiled tubing 10. The electric line is used to
activate one of the perforating guns 100. The electric line is thus
exposed to each potentially corrosive fluid that flows through the
coiled tubing 10. The improved system and process of the present
disclosure provides the benefit of a separate flow path from the
coiled tubing.
[0062] FIG. 2 shows a preferred embodiment of a BHA 5 used in the
ACT-Frac process. The CT string 10, the umbilical tube 20 and
electric line 30 are connected to the BHA 5 through a grapple with
centralizer 13. At the top of the BHA 5 is an electric line and
umbilical anchor release 14 and a double flapper check valve
16.
[0063] The BHA 5 may contain a shear sub 17. If the packer or BHA
becomes stuck in the hole, the upper portion of the BHA can be
separated from the lower portion of the BHA at the shear sub 17.
The BHA may further include an upper universal connect/disconnect
("UCD") 18 connected to a lower UCD 19. A deployment bar 21, which
may include a hydraulic filter, may be connected to the lower UCD
19. The BHA may include a double flapper check valve 22 and memory
gauges 23 above an anchor 80. In a preferred embodiment, the anchor
80 is hydraulically set. In casing sizes of 41/2 inches and smaller
in diameter, the anchor may be located above the packer 70. Wash
ports 55 connected to the CT string 10 may be located between the
anchor 80 and the packer 70 and may be used to wash away proppant
from the packer 70 and the anchor 80, or the entire BHA 5. A bypass
screen 26, 97 may be used to filter the fluid passing through the
bypass. The bypass may allow fluid to travel from below the packer
to above the packer at all times, which may prevent pressure from
building up below the packer 70. The BHA 5 may also contain an
element 24 to rapidly deflate the packer 70 in an emergency.
[0064] The packer may include a packer mandrel 71 that has a spring
loaded sliding end 72. Below the packer mandrel 71 may be a double
flapper check valve 96 that prevents the flow of fluid down the
bypass. Below the double flapper check valve 96 may be a lower
bypass screen 97, a memory gauge 98 for the lower zone of the BHA
5, and a connection 99 to lower elements such as a CCL and/or
perforation guns.
[0065] As shown in FIG. 3, the improved concentric coiled tubing
annular fracturing string includes an umbilical tube 20 contained
inside of the CT string 10. This configuration provides separate
fluid paths 15, 25 for at least two different functions. The
umbilical tube 20 can be used to deliver fluid via fluid path 25 to
inflate a packer 70 and/or to activate a hydraulic set anchor 80.
The umbilical tube 20 may also provide the fluid path 25 for the
release of fluids to deflate the packer 70 and/or deactivate the
hydraulic set anchor 80. The fluid delivered by the umbilical tube
20 may be filtered or be a clean non-corrosive fluid that will not
chemically attack the packer 70 or the anchor 80. Thus, the packer
can be constructed of natural rubber and may be used in repeated
trips of the BHA downhole. In one embodiment, the umbilical 20 tube
may be comprised of a different material than the CT string 10,
such as stainless steel.
[0066] An electric wireline 30 may be run downhole inside the
umbilical tube 20 as shown in FIGS. 2 and 3. The electric wireline
30 may be electrically connected to various elements in the BHA 5.
For example, the electric wireline 30 may be connected to the
perforating guns 100 allowing an electric signal to be sent from
the surface to discharge a selected perforating gun 100. The
electric wireline 30 may be encased by a number of steel cables 40,
such as a 7/32 inch diameter steel cable commercially offered by
Camesa, Inc. of Rosenberg, Tex., which both protects and
strengthens the electric line 30. The umbilical tube 20 may be used
to protect the wireline 30 from acid as electric wirelines are
often galvanized extra plow steel, which is susceptible to
corrosive attack from acids. The electric wireline 30 in the
umbilical tube 20 may also be used to measure the fracturing fluid
pressure as well as the downhole temperature as the electric
wireline 30 may be connected to a pressure transducer and/or a
temperature device. The electric wireline 30 in the umbilical tube
20 may also be used to operate an electrical CCL.
[0067] While the umbilical tube 20 may contain an electric line 30
and may be used to deliver fluid to a packer 70 and/or anchor 80,
the CT string 10 may be used to fluidize settled proppant, and/or
wash proppant out of the wellbore between fracturing procedures.
The CT string 10 may also be used to deliver acid to the fracturing
zone before each fracturing procedure. The CT string 10, attached
to the BHA 5, may include at least one fluid port 55 located near
the top of the packer 70. The at least one fluid port 55 may
include a one way valve, such as a flapper valve 16 (Shown in FIG.
2) for example, to prevent fluid in the well from flowing up the CT
string 10.
[0068] FIG. 4 shows a pressure schematic of an umbilical 20 in
fluid communication via fluid path 25 to both an anchor 80 and a
packer 70. The end of the umbilical 20 may be connected to a check
valve 65 preventing downward flow that is in parallel with a
pressure relief valve 85. The pressure relief valve 85 may be set
at a predetermined pressure, such as 500 psi, thus requiring that
the pressure builds in the umbilical before the pressure relief
valve 85 opens and the hydraulic anchor 80 is activated. Check
valves 65 and pressure relief valve 85 may function together. The
purpose of the valves 65, 85 is to isolate the packer and anchor
from relatively high hydrostatic pressure in the BHA. As described
above, a low specific gravity fluid may be used to create a
relatively low hydrostatic pressure within the BHA when the BHA is
at typical fracturing depths. A relatively low pressure in the BHA
can also be created by pumping fluid into the wellbore depending on
the reservoir's hydraulics. However, it is possible to have a
relatively low pressure within the BHA at typical fracturing
depths, but to have a relatively high pressure within the BHA at
shallower depths. The valves 65, 85 ensure that the pressure in the
BHA does not exceed the pressure in the wellbore so that the packer
may remain deflated and the buttons in the anchor may remain
retracted.
[0069] Below the anchor 80, the hydraulic circuit may include a
pilot operated valve 110 in parallel with both a check valve 115
and another pressure relief valve 95. The check valve 115 prevents
downward flow, but may allow the packer fluid to drain into the
umbilical tube during deflation. An additional check valve 105 may
be used to prevent wellbore fluids from entering the BHA while the
pilot valve 110 is open. The pilot operated valve 110 may be
normally open to the fracturing zone 120 allowing fluid to flow out
of the BHA into the fracturing zone 120. The pilot operated valve
110 is set to close when the pressure in the anchor 80 reaches a
predetermined pressure, such as 4500 psi, above the fracturing zone
120 pressure. The pilot operated valve 110 is set to re-open when
the pressure in the anchor is 2500 psi above the fracturing zone
pressure. This configuration of the pilot operated valve 110
ensures that the anchor 80 is set before the packer 70 inflates and
that the packer 70 deflates before the anchor 80 is deactivated.
The pressure relief valve 95 may be configured such that it is
closed until the pressure in the anchor reaches a predetermined
pressure, such as 5000 psi above the fracturing zone pressure,
which is greater than the closing pressure for the pilot operated
valve 110.
[0070] Once the pressure inside the hydraulic circuit reaches the
predetermined pressure causing the pressure relief valve 95 to
open, the flow through the hydraulic circuit will begin to inflate
the packer 70 expanding the packer 70 against the well casing. The
hydraulic circuit may include a pressure relief valve 75
that-prevents over inflation of the packer. The pressure relief
valve 75 may allow fluid to pass out of the BHA into the fracturing
zone 120 when the pressure in the packer 70 exceeds a predetermined
pressure, such as 1000 psi, above the fracturing zone 120 pressure.
The pressure relief valve 75 ensures that the pressure in the
packer 70 is greater than the pressure in the fracturing zone 120,
but limits the buildup of excess pressure within the packer 70.
Therefore the pressure relief valve 75 enables the packer 70 to
remain 1000 psi above the fracturing zone 120 pressure. In this
manner, the fracturing zone 120 pressure does not need to be well
understood before the fracturing process is started. The packer 70
pressure may dynamically respond increasing as the fracturing zone
120 pressure increases.
[0071] The specific pressure set points of each valve in the
embodiment of FIG. 4 are more illustrative purposes and may be
varied depending on the environmental conditions and type of
application as would be apparent to one of ordinary skill in the
art having the benefit of this disclosure. The embodiment of FIG. 4
may ensure that the packer 70 will have an inflation pressure that
is greater than the surrounding pressure present in the fracturing
zone 120. Additionally, the embodiment provides a relief valve 75
that may prevent the over-inflation of the packer 70. The
embodiment of FIG. 4 also provides that the anchor 80 may remain
set even if the pressure in the packer 70 decreases due to a leak
or a failed packer. Further, the use of the umbilical tube 20 to
inflate the packer 70 may protect the internal portion of the
packer 70 from washing fluids pumped down the CT string 10, which
may be harmful to the rubber elements in the packer 70. The
configuration of FIG. 4 may ensure that the pressure in the anchor
80 is greater than the pressure in the packer 70.
[0072] FIG. 5 shows an embodiment having a direct connection
between the umbilical tube 20 and the packer 70 with a pressure
relief valve 145 in parallel with a check valve 135. The pressure
relief valve 145 is set to open at a predetermined pressure. Such a
configuration may be used with a BHA that does not have an anchor.
The pressure relief valve 145 may be set at a predetermined
pressure, such as 500 psi, thus requiring that the pressure builds
within the umbilical before the pressure relief valve 145 opens and
the packer 70 may be inflated. The valves 135, 145 may function
together to isolate the packer 70 from relatively high hydrostatic
pressure within the BHA. As described above, a low specific gravity
fluid may be used to create a relatively low hydrostatic pressure
within the BHA when the BHA is at typical fracturing depths. A
relatively low pressure within the BHA can also be created by
pumping fluid down the wellbore depending on the reservoir's
hydraulics. However, it is possible to have a relatively low
pressure in the BHA at typical fracturing depths, but to have a
relatively high pressure in the BHA at shallower depths. The valves
135, 145 may prevent the pressure within the BHA from exceeding the
pressure within the wellbore, thus ensuring that the packer 70
remains deflated. In an alternative embodiment of the present
disclosure, an umbilical tube may be connected directly to a packer
without any valves.
[0073] The umbilical connected to either of the hydraulic circuits
shown in FIGS. 4 and 5 may contain a fluid with a specific gravity
lower than water to place a negative pressure on the packer 70 and
anchor 80. The use of such a fluid may help the packer to deflate
to its original deflated size. A number of low specific gravity
fluids may be suitable, such as Petro-Canada's HT 40N drilling mud,
a 50/50 methanol water mixture, as would be appreciated by one of
ordinary skill in the art having the benefit of this disclosure.
Additionally, the use of a low viscosity fluid in the umbilical may
allow for usage in the winter at low temperatures.
[0074] The presence of two fluid paths 15, 25 allows the CT string
10 to be used to deliver a cross linking agent to the fracturing
fluid to cross-link the fluids at the perforations, just before the
fracturing fluid slurry enters the formation. The cross-linking
agent may be pumped down the CT string 10 and enter the casing at
the fracturing zone via circulation ports 55 may allow for better
control of the timing of the cross-linking chemistry.
[0075] The presence of two fluid paths 15, 25 in the concentric
coiled tubing string may also allow for the performance of two
different hydraulic functions without the manipulation of any
valves, This allows the BHA to be simpler and easier to assemble
than the previous design. Additionally, the two fluid paths may
eliminate the need of a highly trained staff to operate the BHA
downhole.
[0076] The presence of two fluid paths 15, 25 may allow the CT
string 10 to be used to determine the fracturing pressure by
measuring the injection pressure into the CT string 10 at surface.
Alternatively, the umbilical string may be used to determine the
fracturing pressure in the same way. Typically the fluid properties
in the CT string 10 are not changing over time and their
proprieties are well understood. In addition, the injection rate
may be low or even static such that the frictional pressure drop
may not complicate the interpretation of the pressure down hole.
Thus, it may be relatively easy to calculate the hydrostatic
pressure in both the CT string 10 and the umbilical tube 20. The
downhole pressure can be substantially determined by slowly pumping
fluid down the CT string 10 such that fluid very slowly exits the
CT string 10 from the circulation ports 55. Because the fluid is
pumped slowly any frictional pressure losses may be disregarded and
the downhole fracturing fluid pressure may be estimated by adding
together the pumping pressure and the hydrostatic pressure of the
fluid within the CT string 10.
[0077] FIG. 6 shows an embodiment of a BHA of the present
disclosure that includes an emergency packer deflation device that
quickly draws the packer fluid 230 out of the inflatable packer 270
once the packer 270 loses its ability to anchor against the casing
240. The emergency packer deflation device may be connected to the
BHA directly above the inflatable packer 270. The emergency packer
deflation device includes a piston rod 130, piston 180, and spring
190 closed within a housing 170. A shear ring 140 connects the
housing 170 to the top portion of the piston rod 130. The emergency
packer deflation device may also include a crush ring 150.
[0078] The BHA may include a bypass filter 200, which contains
bypass fluid 210, between the emergency packer deflation device and
the inflatable packer 270. The packer 270 is inflated with the
inflatable packer fluid 230. The packer 270 includes a packer
mandrel 220 from which it expands. The inflatable packer fluid 230
passes through a mandrel ring 250 that includes flow slots 255
(shown in FIG. 9) to inflate or deflate the packer 270.
[0079] As discussed above, once the packer 270 loses its ability to
anchor the pressure drop across the packer 270 transfers a load
onto the CT string. This load may shear the shear ring 140 allowing
the pressure drop across the packer 270 to push the packer 270
downhole away from the piston rod 130 of emergency packer deflation
device as shown in FIG. 7. The movement of the packer 270 away from
the mandrel 130 of the emergency packer deflation device may cause
the housing 170 to travel relative to the piston 180. The stroking
of the piston 180 may increase the volume within the housing 170
below the piston 180, which may rapidly draw the inflatable packer
fluid 230 out of the packer 270 causing the packer 270 to deflate
as shown in FIG. 8. The packer 270 may be adapted with a large flow
area to allow for the rapid removal of the inflatable packer fluid
230. The smallest cross sectional area in the flow path between the
packer 270 and the emergency packer deflation device is shown in
FIG. 9, section EE in FIG. 6. The emergency packer deflation device
includes a crush ring 150 which may decelerate the housing 170 and
the portion of the BHA connected thereto preventing the housing 170
from damaging the piston 180 once the piston 180 has traveled to
the end of its stroke.
[0080] Once the packer 270 is deflated (shown as 280 in FIG. 8),
the pressure drop across the packer 270 may be greatly reduced,
thus reducing the load on the CT string. Further, as shown in FIG.
10, the emergency packer deflation device may be adapted such that
the pressure within the housing 170 above and below the piston 180
may be equalized with the wellbore pressure after the housing 170
and the packer 270 have come to a rest.
[0081] FIG. 9 shows the cross-section of the mandrel ring 250 of
the embodiment of FIG. 6, section EE. This section represents the
minimum flow area between the packer 270 and the emergency packer
deflation device housing 170. The mandrel ring 250 includes flow
slots 255 which allow for the rapid flow of inflatable packer fluid
230 to the housing 170 so as to rapidly deflate the packer 270. If
the flow area between the packer 270 and the housing 170 is too
small, the result is a large pressure drop between the packer 270
and the housing 170. The pressure in the housing 170 becomes small
relative to the pressure in the packer 270 and as a result there is
a pressure induced force on the piston 180. The force on the piston
180 is reacted by a force from the CT string. This force can become
too large, releasing the emergency release tool or breaking the CT
string, if the flow area is too small. The required flow area is
determined by the rate at which the housing 170 and the packer 270
move down the wellbore once the packer 270 looses its ability to
anchor itself to the casing. As discussed above, the rapid
deflation of the packer 270 is important to prevent an excessive
load on the CT string due to a pressure drop across the packer 270
in the event the packer 270 has lost its ability to anchor against
the casing 240. If the load on the CT string is not decreased, the
CT string may break dropping the BHA into the wellbore.
[0082] Although various embodiments have been shown and described,
the invention is not so limited and will be understood to include
all such modifications and variations as would be apparent to one
skilled in the art.
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