U.S. patent application number 11/091250 was filed with the patent office on 2005-12-15 for apparatus and method for dewatering low pressure gradient gas wells.
Invention is credited to Crabtree, Alexander Raphael, Jackson, T. Roland, Misselbrook, John Gordon.
Application Number | 20050274527 11/091250 |
Document ID | / |
Family ID | 34964603 |
Filed Date | 2005-12-15 |
United States Patent
Application |
20050274527 |
Kind Code |
A1 |
Misselbrook, John Gordon ;
et al. |
December 15, 2005 |
Apparatus and method for dewatering low pressure gradient gas
wells
Abstract
Disclosed is an apparatus and method for removing extraneous
water from a natural gas well using a miniaturized jet pump
assembly and a concentric coiled tubing string. The miniaturized
jet pump assembly is attached to a concentric coiled tubing string
at the surface and then run into the well as a single unit.
Alternatively, the concentric coiled tubing string may be assembled
in the well. Once downhole, the jet pump assembly is activated to
remove extraneous water from the well thereby facilitating the
production of natural gas. Should the functional portion of the jet
pump assembly corrode or wear out, that portion may be uninstalled
and replaced without removing the jet pump assembly and concentric
coiled tubing string from the well.
Inventors: |
Misselbrook, John Gordon;
(Houston, TX) ; Jackson, T. Roland; (Conroe,
TX) ; Crabtree, Alexander Raphael; (Dewinton,
CA) |
Correspondence
Address: |
HOWREY LLP
C/O IP DOCKETING DEPARTMENT
2941 FAIRVIEW PARK DRIVE, SUITE 200
FALLS CHURCH
VA
22042-7195
US
|
Family ID: |
34964603 |
Appl. No.: |
11/091250 |
Filed: |
March 28, 2005 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60559647 |
Apr 5, 2004 |
|
|
|
60589302 |
Jul 20, 2004 |
|
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Current U.S.
Class: |
166/369 ;
166/105 |
Current CPC
Class: |
E21B 19/22 20130101;
E21B 43/124 20130101; E21B 17/203 20130101 |
Class at
Publication: |
166/369 ;
166/105 |
International
Class: |
E21B 043/00 |
Claims
What is claimed is:
1. An assembly for removing produced water from a wellbore, the
assembly comprising: an outer coiled tubing string capable of being
inserted into a production tubing string; an inner coiled tubing
string contained within the outer coiled tubing string; an annular
channel formed between the inner coiled tubing string and the outer
coiled tubing string; an outer tubular member attached to a lower
end of the outer coiled tubing string; a pump housing contained
within the outer tubular member and attached to a lower end of the
inner coiled tubing string; and a jet pump contained within the
pump housing.
2. The assembly of claim 1, further comprising a one-way valve
attached to a lower end of the pump housing, the one-way valve
located below the jet pump.
3. The assembly of claim 1, wherein the jet pump comprises a jet
nozzle, a throat, an upper diffuser, and a lower diffuser.
4. The assembly of claim 1, further comprising a first sealing
assembly located between an outer surface of the jet pump and an
inner surface of the pump housing.
5. The assembly of claim 3, further comprising a second sealing
assembly located between an outer surface of the upper diffuser and
an inner surface of the lower diffuser.
6. The assembly of claim 1, further comprising a third sealing
assembly located between an outer surface of the pump housing and
an inner surface of the outer tubular member.
7. The assembly of claim 1, wherein the jet pump further comprises
a fishing neck.
8. The assembly of claim 1, further comprising a second annular
channel formed between the jet pump and the pump housing.
9. The assembly of claim 8, further comprising a port that is in
fluid communication with the jet pump and the second annular fluid
channel.
10. The assembly of claim 1, further comprising a boot sub attached
to a lower end of the outer tubular member and a lower end of the
pump housing.
11. The assembly of claim 10, wherein the boot sub comprises an
open lower end in fluid communication with the natural gas
wellbore.
12. The assembly of claim 4, wherein at least a portion of the jet
pump can be removed from the pump housing using hydraulic pressure
while the jet pump is located in the wellbore.
13. The assembly of claim 7, wherein at least a portion of the jet
pump can be removed from the pump housing using a wire-line fishing
tool while the jet pump is located in the wellbore.
14. The assembly of claim 1, wherein the production tubing string
has an outer diameter less than or equal to 2-7/8 inches.
15. The assembly of claim 1, wherein the outer coiled tubing string
has an outer diameter less than or equal to 2 inches.
16. The assembly of claim 1, wherein the inner coiled tubing string
has an outer diameter less than or equal to 1 inch.
17. The assembly of claim 1, wherein the jet pump has an outer
diameter of less than 1 inch.
18. The assembly of claim 1, wherein the outer coiled tubing string
is composed of corrosion resistant coiled tubing.
19. The assembly of claim 1, wherein that portion of the outer
coiled tubing string that extends across a perforation in the
wellbore is comprised of corrosion resistant coiled tubing.
20. An assembly for removing produced water from a wellbore, the
assembly comprising: an outer jointed tubing string capable of
being inserted into a production tubing string, wherein at least a
portion of the outer jointed tubing string is made of a corrosion
resistant material; an inner coiled tubing string contained within
the outer jointed tubing string; an annular channel formed between
the inner coiled tubing string and the outer jointed tubing string;
an outer tubular member attached to a lower end of the outer
jointed tubing string; a pump housing contained within the outer
tubular member and attached to a lower end of the inner coiled
tubing string; and a jet pump contained within the pump
housing.
21. The assembly of claim 20, wherein the portion of the outer
jointed tubing string that extends across perforations in the
wellbore is made of corrosion resistant material.
22. A method for removing produced water from a wellbore, the
method comprising: attaching a jet pump assembly to a lower end of
a concentric coiled tubing string, the concentric coiled tubing
string comprising an outer coiled tubing string, an inner coiled
tubing string contained within the outer coiled tubing string, and
an annular fluid channel formed there between; lowering the jet
pump assembly and concentric coiled tubing string through a
production tubing string; pumping a power fluid to the jet pump
assembly through the inner coiled tubing string; jetting the power
fluid through the jet pump assembly to create an area of low
pressure therein; drawing the water from the wellbore into the jet
pump assembly; and pumping the water from the wellbore to the
surface.
23. The method of claim 22, wherein the step of returning the water
from the wellbore to the surface further comprises returning the
water from the wellbore to the surface through the annular fluid
channel.
24. The method of claim 22, further comprising providing the jet
pump assembly with a one-way valve.
25. The method of claim 22, further comprising constructing the
outer coiled tubing with corrosion resistant coiled tubing.
26. The method of claim 22, further comprising constructing that
portion of the outer coiled tubing that extends across a
perforation in the wellbore of corrosion resistant coiled
tubing.
27. The method of claim 22, further comprising providing the
production tubing string with an outer diameter less than or equal
to 2-7/8 inches.
28. The method of claim 22, providing the outer coiled tubing
string with an outer diameter less than or equal to 2 inches.
29. The method of claim 22, providing the inner coiled tubing
string with an outer diameter less than or equal to 1 inch.
30. The method of claim 22, providing the jet pump assembly with an
outer diameter less than or equal to 1 inch.
31. The method of claim 22, further comprising removing at least a
portion of the jet pump assembly from the wellbore without removing
the concentric coiled tubing string from the wellbore.
32. A method for removing produced water from a wellbore, the
method comprising: lowering an outer jointed tubing string into the
wellbore, wherein the outer jointed tubing string is made of
corrosion resistant material; attaching a jet pump assembly to a
lower end of an inner coiled tubing string; lowering the jet pump
assembly and inner coiled tubing string into the outer jointed
tubing string; providing an annular channel between the outer
jointed tubing string and the inner coiled tubing string pumping a
power fluid to the jet pump assembly through the inner coiled
tubing string; jetting the power fluid through the jet pump
assembly to create an area of low pressure therein; drawing the
water from the wellbore into the jet pump assembly; and pumping the
water from the wellbore to the surface.
33. The method of claim 32, further comprising lowering the jet
pump assembly past perforations in the wellbore, wherein the
portion of the outer jointed tubing string that extends across the
perforations is made of corrosion resistant material.
34. A method for removing produced water from a wellbore, the
method comprising: attaching a jetting means to a lower end of a
concentric coiled tubing string, the concentric coiled tubing
string comprising an outer coiled tubing string, an inner coiled
tubing string contained within the outer coiled tubing string, and
an annular channel there between; lowering the jetting means and
concentric coiled tubing string through a production tubing string;
pumping a power fluid to the jetting means through the inner coiled
tubing string; jetting the power fluid through the jetting means to
create an area of low pressure thererin; drawing the water from the
wellbore into the jetting means; and pumping the water from the
wellbore to the surface.
35. The method of claim 34, wherein the step of returning the water
from the wellbore to the surface further comprises returning the
water from the wellbore to the surface through the annular fluid
channel.
36. The method of claim 34, further comprising removing at least a
portion of the jetting means from the wellbore without removing the
concentric coiled tubing from the wellbore.
37. A method for lowering a concentric coiled tubing string into a
wellbore, the method comprising: attaching a seating assembly to a
lower end of an outer coiled tubing string; lowering the seating
assembly and the outer coiled tubing string into the wellbore
through a production tubing string; cutting an upper end of the
outer coiled tubing string and suspending the outer coiled tubing
string above the production tubing string; attaching a jet pump
assembly to a lower end of an inner coiled tubing string; lowering
the jet pump assembly and the inner coiled tubing string into the
outer coiled tubing string until the jet pump assembly seats in the
seating assembly; and cutting an upper end of the inner coiled
tubing string and suspending the the inner coiled tubing string
above the production tubing string.
38. The method of claim 37, wherein the step of attaching the
seating assembly to the lower end of the outer coiled tubing string
further includes attaching at least one flapper valve below the
seating assembly.
39. The method of claim 38, wherein the step of attaching a seating
assembly to a lower end of the outer coiled tubing string further
includes attaching a blow out plug below the seating assembly and
the flapper valve(s).
40. The method of claim 37, wherein the step of attaching the
seating assembly to the lower end of the outer coiled tubing string
further includes providing a sealing bore with the seating
assembly.
41. The method of claim 37, wherein the step of attaching the jet
pump assembly to the lower end of the inner coiled tubing string
further includes attaching a strainer to the inner coiled tubing
string below the jet pump assembly.
42. The method of claim 41, wherein the step of attaching the jet
pump assembly to the lower end of the inner coiled tubing string
further includes attaching a sealing assembly to the inner coiled
tubing string below the jet pump assembly and above the
strainer.
43. The method of claim 37, wherein the jet pump assembly acts as a
mechanical barrier to fluid flow through the inner coiled tubing
string.
44. The method of claim 37, wherein the step of lowering the outer
coiled tubing string and the seating assembly into the wellbore
further comprises lowering the outer coiled tubing string and the
seating assembly through a Christmas tree.
45. The method of claim 37, wherein the step of lowering the inner
coiled tubing string and the jet pump assembly into the wellbore
further comprises lowering the inner coiled tubing string and the
jet pump assembly through a Christmas tree.
46. The method of claim 44, wherein the step of lowering the outer
coiled tubing string and the seating assembly through a Christmas
tree further comprising attaching a slip bowl to the upper end of
the outer coiled tubing string.
47. The method of claim 45, wherein the step of lowering the inner
coiled tubing string and the seating assembly through a Christmas
tree further comprising attaching a slip bowl to the upper end of
the inner coiled tubing string.
48. The method of claims 46, wherein the step of attaching a slip
bowl to the upper end of the outer coiled tubing string further
comprises suspending the slip bowl in a spool piece.
49. The method of claims 47, wherein the step of attaching a slip
bowl to the upper end of the inner coiled tubing string further
comprises suspending the slip bowl in a spool piece.
50. The method of claim 37, further comprising constructing the
outer coiled tubing string of corrosion resistant coiled
tubing.
51. The method of claim 37, further comprising constructing that
portion of the outer coiled tubing string that extends across a
perforation in the wellbore of corrosion resistant coiled
tubing.
52. A method for lowering a concentric coiled tubing string into a
wellbore, the method comprising: attaching a seating assembly to a
lower end of an outer coiled tubing string; lowering the seating
assembly and the outer coiled tubing string into the wellbore
through a production tubing string; cutting an upper end of the
outer coiled tubing string; suspending the outer coiled tubing
string above the production tubing string using suspending means;
attaching a jet pump assembly to a lower end of an inner coiled
tubing string; lowering the jet pump assembly and the inner coiled
tubing string into the outer coiled tubing string until the jet
pump assembly seats in the seating assembly; and cutting an upper
end of the inner coiled tubing string; and suspending the inner
coiled tubing string above the production tubing string using the
suspending means.
53. A method for removing a concentric coiled tubing string from a
wellbore, wherein the concentric coiled tubing string comprises an
outer coiled tubing string positioned within a production tubing
string, and an inner coiled tubing string located within the outer
coiled tubing string, the method comprising: removing a portion of
a jet pump assembly from the wellbore, wherein the jet pump
assembly is attached to the lower end of the inner coiled tubing
string; lowering a portion of a dummy jet pump assembly into the
natural gas wellbore through the inner coiled tubing string;
seating the dummy jet pump assembly in a seating assembly attached
to the lower end of the outer coiled tubing string, wherein the jet
pump dummy assembly prohibits fluid flow through the inner coiled
tubing string; removing the inner coiled tubing string and the jet
pump dummy assembly from the wellbore; lowering a wireline plug
into the wellbore through the outer coiled tubing string; seating
the wireline plug in the seating assembly attached to the lower end
of the outer coiled tubing string, wherein the wireline plug
prohibits fluid flow through the outer coiled tubing string toward
the surface position; and removing the outer coiled tubing string
and the wireline plug from the wellbore.
54. An assembly for removing produced water from a wellbore, the
assembly comprising: an outer coiled tubing string; an inner coiled
tubing string contained within the outer coiled tubing string; an
annular channel formed between the inner coiled tubing string and
the outer coiled tubing string; an outer tubular member attached to
a lower end of the outer coiled tubing string; a pump housing
contained within the outer tubular member and attached to a lower
end of the inner coiled tubing string; and a jet pump contained
within the pump housing, wherein at least a portion of the jet pump
can be removed from the wellbore without removing either the outer
coiled tubing string or the inner coiled tubing string.
55. A method for removing produced water from a wellbore, the
method comprising: attaching a jet pump assembly to a lower end of
a concentric coiled tubing string, the concentric coiled tubing
string comprising an outer coiled tubing string, an inner coiled
tubing string contained within the outer coiled tubing string, and
an annular fluid channel formed there between; lowering the jet
pump assembly and concentric coiled tubing string into the
wellbore; pumping a power fluid to the jet pump assembly through
the inner coiled tubing string; jetting the power fluid through the
jet pump assembly to create an area of low pressure therein;
drawing the water from the wellbore into the jet pump assembly;
pumping the water from the wellbore to the surface; and removing at
least a portion of the jet pump assembly from the wellbore without
removing the concentric coiled tubing string.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of priority to U.S.
Provisional Application No. 60/559,647, filed Apr. 5, 2004, and
U.S. Provisional Application No. 60/589,302, filed Jul. 20, 2004,
which are both herein incorporated by reference in their
entirety.
BACKGROUND OF THE INVENTION
[0002] In a typical oil or natural gas recovery process, after a
well has been drilled, a tubular casing is lowered into and
cemented within the wellbore. Cementing of the casing string
usually includes lowering the casing to a desired depth and
displacing a desired volume of cement down the inner diameter of
the casing. Cement is displaced downward into the casing until it
exits the bottom of the casing and moves up into the annular space
between the outer diameter of the casing and the wellbore. The
cement cures to firmly anchor the casing to the walls of the
wellbore and seal off the well.
[0003] To access the oil or natural gas through the now sealed well
casing, both the casing and concrete are perforated at a
predetermined downhole location. The oil or natural gas moves from
the formation into the well casing via the perforations due to the
difference in pressure between the formation and the well casing
interior. This pressure differential carries the oil or natural gas
to the surface where it is collected.
[0004] With regard to the production of natural gas, many such
wells produce small amounts of liquid along with the gas.
Initially, when the pressure differential is significant, the
liquid is carried to the surface with the natural gas. In addition,
the well production tubulars are sized to maintain a practical flow
velocity to keep the well unloaded during much of its producing
life. However, as the formation pressure decreases, it becomes
increasingly difficult for the gas velocity to carry the associated
liquid to the surface. Accordingly, the well begins to load up with
liquid, which has a negative impact on natural gas production.
[0005] Several methods have been developed to alleviate the
problems associated with this liquid loading. One method involves
intermittent production and unloading cycles (e.g., plunger lift),
while another employs reduced sized tubulars (e.g., velocity
strings) to increase gas velocity to a level sufficient to carry
the liquid out of the well. Yet another method uses a capillary
string to inject foamer into the well, which can improve the
transport of liquid. While all are somewhat beneficial, each of
these methods generally results in a lower gas production rate than
if the well was allowed to produce gas without having to also carry
the liquid.
[0006] Many gas wells are originally fitted, or re-completed, with
relatively small production tubing in an attempt to maintain
velocities sufficient to unload produced liquids. Accordingly, the
introduction of any device into the production tubing capable of
removing the unwanted liquid further limits the area in which
natural gas can flow to the surface. The present invention
minimizes this problem, removing the extraneous liquid from a
natural gas well using a miniaturized jet pump assembly attached to
an undersized concentric coiled tubing string.
[0007] The use of jet pumps for removing large amounts of liquid
from wellbores is well known in the prior art. Briefly, jet pumps
generally include a power fluid line operably coupled to the
entrance of the jet pump, and a return line coupled to receive
fluids from a discharge end of the pump. As the pressurized power
fluid is forced, by a pump at the surface, down through the jet
pump, the power fluid draws in and intermixes with the produced
fluid. The power fluid and produced fluid are then returned to the
surface through the return line. Down-hole jet pumps are
advantageous because they have no moving parts, which increase
their reliability over the more conventional mechanical pumps.
[0008] Many jet pump installations incorporate removable
sub-assemblies that enable the sub-assembly to be removed remotely
from the jet pump body while leaving the jet pump body intact in
the well. Such jet pump sub-assemblies, also called "carriers," can
be installed for operation by pumping the "carrier" down the
tubing, and may also be removed by reversing the flow of the power
fluid. Hence, the "removable" jet pump may be adjusted and/or
replaced without requiring that the tubing be pulled from the
well.
[0009] Concentric coiled tubing or coiled-in-coiled tubing is also
known in the prior art. Concentric coiled tubing strings provide
two channels for fluid communication downhole, typically with one
channel, such as the inner channel, used to pump fluid (liquid,
gas, or multiphase fluid) downhole with a second channel, such as
the annular channel formed between the concentric strings, used to
return fluid to the surface. Which channel is used for which
function is a matter of design choice. Both concentric coiled
tubing channels could be used to pump up or down.
[0010] While both of these concepts are known in the prior art, the
two have not been combined, reduced significantly in size, and
employed to remove small amounts of extraneous liquid from a deep,
undersized natural gas well. The rising price of natural gas has
made such a system viable. Accordingly, the following invention
demonstrates such.
SUMMARY OF THE INVENTION
[0011] This invention relates to a method of removing extraneous
fluid from a subterranean petroleum reservoir. More particularly,
this invention relates to a method of removing water from a natural
gas well using a miniaturized jet pump assembly attached to an
undersized concentric coiled tubing string.
[0012] In one embodiment of the present invention, a miniaturized
jet pump assembly is attached to a concentric coiled tubing string
at the surface and is run in the well as one unit. The jet pump
assembly is typically placed below the formation perforations, in
an area adjacent the extraneous water. Once correctly positioned, a
power fluid is pumped down the concentric coiled tubing and used to
activate the functional portion of the jet pump assembly. When
activated, the jet pump assembly creates an area of low pressure
that draws the extraneous water into the assembly. This extraneous
water is intermixed with the power fluid and returned to the
surface via the concentric coiled tubing, where it can be collected
or reused.
[0013] More often than not, the functional portion of the jet pump
assembly wears out with extensive use. Rather than remove the
entire concentric coiled string and assembly from the well to
replace the worn-out components, the functional portion can be
removed from the jet pump assembly by "reversing" the power fluid
flow within the concentric coiled tubing. Once the worn portion of
the jet pump assembly has been replaced, the new components are
pumped downhole to their appropriate location.
[0014] The dimensions of the jet pump apparatus and concentric
coiled tubing string are an important part of the present
invention. Many wells have relatively small production tubing at
that portion of the wellbore that is producing the natural gas.
Accordingly, the introduction of concentric coiled tubing into the
production tubing further limits the area in which natural gas can
flow to the surface. Therefore, it is desirable to utilize the
smallest tubing possible. Small tubing necessarily requires a small
jet pump to allow passage of the "carrier" sub-assembly through the
inner coiled tubing string. As opposed to similar systems in the
prior art, the present invention requires the concentric coiled
tubing string to be small enough to fit inside undersized
production tubing (typically with an outer diameter as small as
2-3/8" and 2-7/8"), and the attached jet pump apparatus to be
effectively miniaturized.
[0015] Another embodiment of the present invention is directed to
an assembly and method for removing produced water essentially
identical to the embodiment described above, except that a jointed
tubing string is used for the outer tubing string instead of the
previously referenced coiled tubing string. In this embodiment, the
outer jointed tubing string may be comprised of a
corrosion-resistant material. The corrosion-resistant material may
extend the entire length of the outer jointed tubing string, or it
may be included only in those portions of the jointed tubing string
that will be adjacent to the perforations in the wellbore.
[0016] Still another embodiment of the present invention is
directed to a method of installing the jet pump assembly and
concentric coiled tubing string in a wellbore. This method includes
running an outer coiled tubing string into a wellbore, cutting the
outer tubing string and hanging it off in a "Christmas tree,"
running an inner coiled tubing string (with the jet pump assembly
attached) through the outer tubing string, cutting the inner tubing
string, landing the jet pump assembly in a specially designed
seating assembly (attached to the bottom of the previously run
outer coiled tubing string), and finally hanging off the inner
string in the Christmas tree on the surface. This method is
particularly well suited for offshore use where lifting a spool of
concentric coiled tubing is not feasible.
[0017] To ensure oil and/or natural gas cannot flow freely to the
surface when a wellbore is open to the atmosphere, certain
jurisdictions require one or more mechanical flow barriers to be
maintained in the wellbore. The act of placing an inner coiled
tubing string inside of an outer coiled tubing string and hanging
it off (as referenced above) results in just such a situation where
the wellbore is open to the atmosphere. Thus, when running a
concentric coiled tubing string into a well it is usually necessary
to include at least one mechanical barrier below the aforementioned
jet pump assembly.
[0018] The permutation of a check valve, a blow out plug, an
extended seal bore, a nipple profile, and a seating assembly
attached to the outer coiled tubing string, together with the use
of a dummy carrier set in the jet pump assembly and attached to the
inner concentric coiled tubing string, provides a means of
installing a concentric coiled tubing jet pump dewatering system in
a natural gas well while maintaining one or more mechanical
barriers during the process.
[0019] Another embodiment of the present invention is directed to a
method of removing the jet pump assembly and concentric coiled
tubing string from the wellbore. This method includes replacing a
working carrier in the jet pump assembly with a dummy carrier,
removing the inner coiled tubing string from within the outer
coiled tubing string, placing a wireline plug in the lower end of
the outer coiled tubing, pressure testing the wireline plug, and
thereafter removing the outer coiled tubing string from the well.
As with installing the concentric coiled tubing string and jet pump
assembly in the wellbore, it is necessary maintain one or more
mechanical barriers during the process of removing the concentric
coiled tubing string and jet pump assembly. The method outlined
above (and described in more detail below) accomplishes this
objective.
[0020] Additional objects and advantages of the invention will
become apparent as the following detailed description of the
preferred embodiment is read in conjunction with the drawings. It
should be noted that terminology such as "up," "down," "above,"
"below," and the like are used herein for convenience. These terms
may not be technically accurate, as when an embodiment of the
present invention is used in a horizontal wellbore. The terms "up"
and "above" and the like generally refer to a direction toward the
surface of a wellbore, while the terms "down" and "below" and the
like generally refer to a direction away from the surface of a
wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0021] FIG. 1 shows a longitudinal cross section of a jet pump
assembly of the present invention.
[0022] FIG. 2 shows an alternative view of a longitudinal cross
section of a jet pump assembly of the present invention.
[0023] FIG. 3 illustrates surface equipment used in a method
according to one embodiment of the invention wherein the concentric
coiled tubing string is assembled in the well bore. The outer
coiled tubing string is illustrated being run into the existing
production tubing in the well.
[0024] FIG. 4 illustrates the bottom hole assembly attached to the
bottom of the outer coiled tubing string according to the method of
one embodiment of the present invention.
[0025] FIG. 5 illustrates the outer coiled tubing string having
been cut according to the method of one embodiment of the present
invention.
[0026] FIG. 6 illustrates the installation of the slip bowl on the
outer coiled tubing string according to the method of one
embodiment of the present invention.
[0027] FIG. 7 illustrates the landing of the slip bowl on the outer
coiled tubing string according to the method of one embodiment of
the present invention.
[0028] FIG. 8 illustrates the outer coiled tubing string landed in
the Christmas tree spool according to the method of one embodiment
of the present invention.
[0029] FIG. 9 illustrates the jet pump assembly attached to the
inner coiled tubing string according to the method of one
embodiment of the present invention.
[0030] FIG. 10 illustrates the installation of the slip bowl on the
inner coiled tubing string according to the method of one
embodiment of the present invention.
[0031] FIG. 11 illustrates the location of the jet pump assembly
during the step of removing the blow out plug from the bottom sub
of the seating assembly according to the method of one embodiment
of the present invention.
[0032] FIG. 12 illustrates the lowering of the inner coiled tubing
string according to the method of one embodiment of the present
invention.
[0033] FIG. 13 illustrates the passing of the stinger on the jet
pump assembly through the flapper valve and landing of the jet pump
assembly in the seating assembly according to the method of one
embodiment of the present invention.
[0034] FIG. 14 illustrates a plug set in the nipple profile of the
jet pump assembly according to the method of one embodiment of the
present invention.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0035] FIGS. 1 and 2 illustrate a jet pump apparatus (1) in
accordance with the present invention. In the embodiment disclosed
in FIGS. 1 and 2, the jet pump apparatus (1) is comprised of an
outer tubular member, referred to herein as the "shroud" (2). The
shroud (2) is attached to an outer coiled tubing string (not shown)
by any suitable means, but preferably by welding. Welding the
shroud (2) to the outer coiled tubing string allows for a smooth
connection profile between the coiled tubing and the shroud (2),
thereby simplifying the surface installation and preventing any
hang-ups when running the jet pump apparatus (1) into the wellbore.
In an alternative embodiment, the outer tubing string (not shown)
is a jointed tubing string. With a jointed tubing string, the
shroud (2) may be threaded onto the lower end of the jointed tubing
string.
[0036] Contained within the shroud (2) is an inner tubular member
referred to as the pump housing (3). The pump housing (3) is
attached to the inner coiled tubing string (not shown) by any
suitable means, but preferably by means of a threaded connection. A
first annulus (4) is formed between the inner surface of the shroud
(2) and the outer surface of the pump housing (3). The first
annulus (4) is in fluid communication with both the wellbore and
any surface equipment.
[0037] Contained within the pump housing (3) is the functional
portion of the jet pump apparatus (1) referred to, in total, as the
carrier (5). A second annulus (6) is formed between the inner
surface of the pump housing (3) and the outer surface of the
carrier (5). As with the first annulus (4), the second annulus (6)
is in fluid communication with both the wellbore and any surface
equipment.
[0038] Moving from the top of the carrier (5) downward, the carrier
(5) essentially comprises a jet nozzle (7), a throat (8), and the
uppermost portion of a diffuser (9a). Near the jet nozzle portion
(7) of the carrier (5) is located a series of first sealing members
(10), which in this embodiment take the form of three O-rings.
These first sealing members (10) create a seal between the outer
surface of the carrier (5) and the inner surface of the pump
housing (3). Located near the uppermost portion of the diffuser
(9a) is a second series of sealing members (17), which in this
embodiment take the form of two O-rings. These second sealing
members (17) create a seal between the outer surface of the carrier
(5) and the lowermost portion of the diffuser (9b).
[0039] Below the carrier (5) is located a one-way check valve (11).
The check valve (11) can be any suitable one-way-type valve, but is
preferably a ball valve. The check valve (11) only allows fluid to
enter the jet pump apparatus (1), rather than exit. Therefore, any
fluid located within the concentric coiled tubing string is
prohibited from draining out of the bottom of the tool and into the
wellbore. As with the carrier (5), the check valve (11) is located
inside the pump housing (3).
[0040] Below the check valve (11) is located a third series of
sealing members (12), which in this embodiment again take the form
of three O-rings. These sealing members (12) create a seal between
the outer surface of the pump housing (3) and the inner surface of
the shroud (2).
[0041] At the very bottom of the jet pump apparatus (1) is located
a boot sub (13). The boot sub (13) is essentially attached to both
the shroud (2) and the pump housing (3)--the attachment preferably
consisting of one threaded connection and two shoulders. The dual
shoulders help to maintain the positional integrity of the shroud
(2) and the pump housing (3) as the inner concentric coiled tubing
string attempts to expand and shift due to pressure and temperature
changes. The boot sub contains a bore (14) in the lower portion
thereof, which provides fluid communication between the wellbore
and the inner components of the jet pump apparatus (1).
[0042] In operation, the embodiment of the jet pump apparatus (1)
disclosed in FIGS. 1 and 2 is attached to concentric coiled tubing
(not shown) at the surface as described above. Because the jet pump
apparatus (1) is made up entirely at the surface, it can be tested
and checked prior to placing the apparatus downhole. Once tested,
the jet pump apparatus (1) and concentric coiled tubing string are
run into the wellbore together. Typically, the complete apparatus
is run in such that the jet pump apparatus (1) is placed below the
perforations, at or near the location of extraneous water.
[0043] It is a well-known practice in the art to avoid running
standard steel coiled tubing across natural gas perforations.
Natural gas production can corrode that portion of a standard steel
coiled tubing that is adjacent to the perforations. This "jet
impingement" corrosion can vary based on the concentration and type
of dissolved solids, formation brine, and acid gases. Accordingly,
one embodiment of the present invention includes utilizing a
corrosion-resistant material for the outer coiled tubing string
(not shown). Typically, a corrosion resistant alloy (CRA) is used.
In laboratory tests, Nitronic 30 stainless steel has proved to be
corrosion resistant under simulated downhole conditions, although
any suitable CRA can be used. The CRA material can extend the
entire length of the outer coiled tubing string, or it may be
included only in those portions of the coiled tubing that will be
adjacent to the perforations (as a cost savings measure). If the
CRA material is only included in a section of the outer coiled
tubing string, it may be connected to the standard section by any
suitable means, including welding or threaded connections.
[0044] In an alternative embodiment, a jointed tubing string (not
shown) is used for the outer tubing string instead of the
previously mentioned coiled tubing string. The outer jointed tubing
string is made of the corrosion-resistant material referenced
above. As with the coiled tubing string, the CRA material can
extend the entire length of the outer jointed tubing string, or it
may be included only in those portions of the jointed tubing string
that will be adjacent to the perforations in the wellbore (as a
cost savings measure). Nitronic 30 stainless steel has proved to be
corrosion resistant when used with a jointed tubing string,
although any other suitable CRA can be used. If the CRA material is
only included in a section of the outer jointed tubing string, it
may be connected to the standard section by any suitable means,
including welding or threaded connections.
[0045] Once the jet pump apparatus (1) is lowered to the desired
depth, a power fluid is pumped from the surface, down the inner
coiled tubing (not shown) toward the jet pump apparatus (1). The
power fluid can be any suitable substance, although produced water
is preferred for cost savings. The power fluid is pumped into the
pump housing (3) and eventually reaches the carrier (5). Once the
power fluid reaches the carrier (5), it is initially forced through
the jet nozzle (7). The power fluid exists the jet nozzle (7) at a
high rate of speed and travels downward into the throat (8). From
there, the power fluid moves into the uppermost portion of the
diffuser (9a) and subsequently into the lowermost portion of the
diffuser (9b). The power fluid is then forced out of the lowermost
portion of the diffuser (9b) via the diffuser opening (15). At this
point, the power fluid is forced into the first annulus (4) between
the inner surface of the shroud (2) and the outer surface of the
pump housing (3). The power fluid is then returned to the surface
via the first annulus (4) to be re-circulated or collected.
[0046] The act of pumping the power fluid from the surface down to
the jet pump apparatus (1) and through the jet nozzle (7), throat
(8), and diffuser portions (9a and b), creates an area of low
pressure within the pump housing (3). As noted previously, fluid
communication is provided between the pump housing (3) and the
wellbore via the bore (14) of the boot sub (13). Accordingly, any
extraneous fluid (e.g., water) that is present in the wellbore near
the boot sub (13) will be sucked into the jet pump apparatus (1)
due to the area of low pressure created by the power fluid
stream.
[0047] The extraneous water is sucked into the bore (14) of the
boot sub (13) and past the one-way check valve (11) located at the
top of the bore (14). The extraneous water then moves up the second
annulus (6) until it reaches a port (16) near the jet nozzle (7) of
the carrier (5). As noted earlier, the flow of the power fluid
through the jet nozzle (7) creates an area of low pressure in the
immediate vicinity. Accordingly, the extraneous water is sucked
through the port (16) where it intermixes with the power fluid.
Thereafter, the extraneous water and power fluid move through the
carrier (5) and back to the surface as described previously.
[0048] The jet pump apparatus (1) of the present invention requires
a relatively low amount of operational horsepower in comparison
with prior art jet pump systems. As an example, ignoring friction,
the removal of 20 barrels of produced water a day from an 8,000 ft.
well only requires an output of approximately 1.2 horsepower from
an operating jet pump assembly (1). Because the present invention
is designed to remove only a relatively small amount of produced
water from the wellbore, the surface equipment (not shown)
operating the jet pump apparatus can be relatively small (e.g. 10
horsepower) and can function economically even though the jet pump
may be operating inefficiently (e.g., at approximately 20%
efficiency or less). Accordingly, the jet pump assembly (1) of the
present invention is financially viable.
[0049] In a typical oilfield application, certain portions of the
jet pump apparatus (1) wear out or corrode with extensive use. This
wear usually occurs with regard to the carrier (5) and its
sub-components. Instead of removing the entire concentric coiled
tubing string and jet pump apparatus (1) from the well bore, which
is time consuming and costly, the present invention allows for the
removal of the worn parts without removing the entire apparatus
from the wellbore.
[0050] To remove the carrier (5) from the jet pump apparatus (1),
power fluid is "reverse circulated" down the first annulus (4)
formed between the inner surface of the shroud (2) and the outer
surface of the pump housing (3). The power fluid is prevented from
exiting the jet pump apparatus (1) by the one-way check valve (11),
which only allows fluid to flow into the tool, rather than out.
Pressure builds up against the carrier (5) to the point where the
entire assembly, including the first and second sealing members (10
and 17) are removed from the jet pump apparatus (1) and forced
towards the surface. A tool trap (not shown) or similar device is
then employed to retrieve the carrier (5). Once the worn carrier
(5) is removed, a new carrier (5) is pumped back downhole through
the inner coiled tubing (not shown) until it reaches the
appropriate location in the jet pump apparatus (1).
[0051] If, for any reason, it is impossible to generate enough
pressure to force the worn carrier (5) to the surface, a back up
system is included on the jet pump apparatus (1). A fishing neck
(18) is included on the top of the carrier (5). If the carrier (5)
cannot be removed by reverse circulation, a wire-line fishing tool
can be lowered into the inner coiled tubing, stabbed into the
fishing neck (18), and utilized to remove the carrier
mechanically.
[0052] In an alternative embodiment of the jet pump apparatus (1)
disclosed in FIGS. 1 and 2, the one-way check valve (11) can be
omitted from the design of the jet pump apparatus (1). Without the
one-way check valve (11) in place, the power fluid will drain out
of the bottom of the jet pump apparatus (1) and into the wellbore
when the surface pump is switched off. This design would allow for
a corrosion inhibitor to be added to the power fluid and
subsequently introduced into the wellbore. Of course, without the
one-way check valve (11) in place, the carrier (5) cannot be
"reverse circulated" as described above. A wire-line unit (not
shown) would be required to accomplish such a task.
[0053] The dimensions of the jet pump apparatus and concentric
coiled tubing string are an important part of the present
invention. Many wells have relatively small production tubing at
that portion of the wellbore that is producing the natural gas.
Accordingly, the introduction of concentric coiled tubing into the
production tubing further limits the area in which natural gas can
flow to the surface. Therefore, it is desirable to utilize the
smallest tubing/tools possible that will remove the extraneous
water and still provide sufficient flow area for natural gas
production.
[0054] Assuming that production tubing has an outer diameter of
2-7/8 inches, the corresponding inner diameter would only be
approximately 2-2/5 inches. The concentric coiled tubing and
attached jet pump assembly of the present invention must be small
enough to be run inside the production tubing and still leave
adequate annular space to produce the natural gas. Additionally,
there must be adequate annular space within the concentric coiled
tubing to remove any extraneous water as described in the method
above.
[0055] Therefore, as opposed to similar systems in the prior art,
the present invention requires the concentric coiled tubing string
to be extremely small, and the attached jet pump apparatus (1) to
be effectively miniaturized. By way of example, the concentric
coiled tubing may be assembled using 2", 13/4", or even 11/2"
coiled tubing for the outer string and 1" or 7/8" coiled tubing for
the inner string. The jet pump apparatus (1) may be approximately
11/4" in diameter with a "carrier" in the approximate range of 5/8"
to 3/4" depending on the inner string size. Intermediate sizes of
coiled tubing can be manufactured to further optimize performance
if demand warrants it.
[0056] As opposed to assembling the concentric coiled tubing string
at the surface (as described above), there may be circumstances
that require the assembly of the concentric coiled tubing string in
the wellbore. An example of this would be an offshore installation
where the existing platform crane has insufficient capacity to lift
the weight of a pre-assembled concentric coiled tubing reel.
Therefore, another embodiment of the present invention (as
described in more detail below) includes a method of running an
outer coiled tubing string into a wellbore, cutting the outer
tubing string and hanging it off in the "Christmas tree," running
an inner coiled tubing string (with the jet pump assembly attached)
through the outer tubing string, cutting the inner tubing string,
landing the jet pump assembly in a specially designed seating
assembly (attached to the bottom of the previously run outer coiled
tubing string), and finally hanging off the inner string in the
Christmas tree on the surface.
[0057] FIG. 3 illustrates some of the surface equipment used to
assemble the concentric coiled tubing string and lower it into the
wellbore. Prior to lowering the outer coiled tubing (25) into the
wellbore, a new spool piece (30) is installed between a master
valve (35) and the remainder of the Christmas tree (34). A coiled
tubing blow out preventer ("BOP") stack (40) is installed on top of
the master valve (35). The BOP stack (40) includes a plurality of
hydraulically actuated rams such as shear rams, slip rams, and/or
tubing or pipe rams. A hydraulically actuated work window (45) is
attached between the BOP stack (40) and a lubricator (50). A
stuffing box (55) is located above the lubricator and beneath an
injector head (60). The devices above (e.g., injector head,
stuffing box, lubricator, work window, and BOP stack) and their
respective uses are well known in coiled tubing applications.
[0058] At the surface, a bottom hole assembly ("BHA") (75) is
assembled and attached to the bottom of the outer coiled tubing
(25), preferably by a threaded connection. The BHA, as shown in
FIG. 4, comprises a seating assembly (80), a valve body (85), and a
bottom sub (90). The seating assembly (80) further comprises a
landing shoulder (81), an extended seal bore (82), and a
nipple-profile (83). The valve body (85) is connected to the lower
end of the seating assembly (80) by any suitable means such as a
threaded connection. In a preferred embodiment, the valve body (85)
houses a spring-biased flapper (87), which, in the closed position,
will prevent the flow of well bore fluids up through the valve and
into the outer coiled tubing. For those jurisdictions that require
double mechanical barriers to be in place when the well is open to
the atmosphere, dual flapper valves (not shown) can be
utilized.
[0059] The bottom sub (90) is preferably threaded to the lowermost
end of the valve body (85) and includes a profile (92) for
receiving a removable blow out plug (95), which can be
pre-installed in the bottom sub. While a variety of well-known blow
out plugs may be used with this invention, the blow out plug
disclosed in FIG. 4 includes a plurality of "dogs" that extend
radially into the aforementioned profile (92). Once installed in
the bottom sub (90), the blow out plug may be pressure tested while
still on the surface.
[0060] After the BHA is connected to the outer coiled tubing string
(25), the string is fed through the surface equipment by the
injector head (60) and into existing natural gas production tubing
(70), as illustrated in FIG. 3. The outer coiled tubing string (25)
is lowered through the production tubing (70) until it reaches the
desired depth in the wellbore. The flapper valve (87) and blow out
plug (95) serve as dual mechanical barriers to fluid flow when the
outer coiled tubing (25) is being run into the well.
[0061] Once the outer coiled tubing string (25) has been lowered to
the desired depth, it is landed in the spool (30). This can be
accomplished by closing slip rams (41) in the BOP stack to grip the
outer coiled tubing (25) and closing tubing rams (42) to seal the
annulus around the tubing (25), as illustrated in FIG. 5. The work
window (45) is then opened and the outer coiled tubing (25) is cut
by any suitable means such as a mechanical pipe cutter.
[0062] With the window (45) still open, a hang-off bushing or "slip
bowl" (100) may be attached to the top of the severed tubing (25)
by any suitable means. Preferably, the slip bowl (100) is bolted to
the outer coiled tubing string (25) and includes one or more seals
(105). The slip bowl (100) includes a profile (106) for receiving
and connecting to an "overshot" (110). The overshot (110) is
attached to the end of the severed outer coiled tubing (25A), as
shown in FIG. 6.
[0063] The severed coiled tubing (25A) is then lowered until the
overshot (110) latches onto the profile of the slip bowl (100). In
the latched position, the overshot (110) can support the weight of
the suspended outer coiled tubing string (25) and the BHA (75).
After closing the work window (45), tubing rams (42) and slip rams
(41) are opened and the outer coiled tubing (25) is lowered until
the bowl (100) lands on the lowermost shoulder in the bore of the
spool (30), as shown in FIG. 7. Once landed, the spool (30)
supports the weight of the outer tubing string (25). Seals (105)
seal against the internal bore of the spool (30). A latch (not
shown) is then released from the profile (106) of the slip bowl
(100) by any suitable means such as fluid pressure. FIG. 8
illustrates the outer tubing string (25) landed in the spool (30).
The severed coiled tubing (25A) is then removed from the surface
equipment.
[0064] Once the outer coiled tubing string (25) has been landed and
the severed tubing (25A) has been removed, the master valve (35) is
closed and the BOP stack (40) is changed out in preparation for
running the inner string (125) of the concentric coiled tubing
string. An inner string BHA (130), shown in FIG. 9, preferably
comprises a jet pump assembly (135), a standing or check valve
(140), a landing shoulder (145), a seal assembly (150), and a
stinger (155). For added safety, a dummy carrier (not shown) may be
installed in the jet pump assembly as an additional mechanical
barrier.
[0065] The BHA (130) can be connected together by any suitable
means such as by threaded connections between the components.
Preferably, the BHA (130) is threaded to the bottom of the inner
coiled tubing (125) after the inner coiled tubing (125) has been
aligned with and lowered into the surface equipment. After the BHA
(130) is assembled and connected to the inner coiled tubing (125),
the inner coiled tubing is lowered into the outer coiled tubing
(25) by the injector head (60). One of skill in the art will
recognize that the injector head (60) can be adapted to handle the
smaller diameter inner coiled tubing (125).
[0066] The inner coiled tubing (125) may be lowered into the outer
coiled tubing (25) until the inner BHA (130) reaches the outer BHA
(75). The inner coiled tubing (125) may be cut in the same manner
as the outer coiled string (25). Specifically, the slip rams (41)
and tubing rams (42) are closed about the inner tubing string
(125). After the pressure is bled off from above the tubing rams
(42), the work window. (45) is opened and the tubing is cut with an
appropriately sized pipe cutter.
[0067] A slip bowl (175) is connected to the top end of the
suspended inner coiled tubing string (125), as shown in FIG. 10.
The slip bowl (175) includes an outer diameter that will allow the
bowl to land on the upper shoulder of the spool (30) and has a
suitable seal assembly, such as plurality of o-ring seals, that
will seal against the upper seal bore of the spool (30). An
overshot (180) is attached to the lower end of the severed tubing
(125A). The overshot (180) is lowered over and latched to the
upwardly extending profile on the slip bowl (175). The slip rams
(41) and tubing rams (42) are then opened.
[0068] The inner string (125) may then be slowly lowered until the
blow out plug (95) is tagged to verify the location of the BHA
(130). However, before landing the inner coiled tubing string (125)
in the spool (30), the inner string is picked up a short distance
to verify that the seal assembly (150) is not engaged in the seal
bore (82), as shown in FIG. 11. When the lower BHA (130) is in the
position shown in FIG. 11, the position of the slip bowl (175)
relative to the spool (30) is illustrated in FIG. 12. Pressure may
then be applied via a jet pump circulating port (32) to the annulus
(151) between the inner coiled tubing (125) and the outer coiled
tubing (25). The pressure opens the flapper (87) and is applied
against the blow out plug (95). The pressure is increased until the
plug (95) is expelled from the bottom sub (90).
[0069] The release of the plug (95) from the bottom sub will be
indicated by a sudden reduction in surface pressure. As soon as the
plug (95) has been released, the inner tubing string (125) is
lowered and landed in the spool (30). Thus, for a moment, there
will be only one mechanical barrier (i.e., the flapper (87))
downhole.
[0070] As the inner string (125) is lowered, a stinger (155) will
pass through the flapper (87), holding the flapper in the open
position, and will extend past the bottom sub (90) as shown in FIG.
13. However, the seal assembly (150) will encounter the seal bore
(82) prior to the opening of the flapper (87), thereby providing
another downhole barrier. A shoulder (145) on the inner string BHA
(130) will land on the landing shoulder (81) to give a positive
indication that the seal assembly (150) and the stinger (155) are
properly located within the outer BHA (75). Shoulders (145) and
(81) may also be used to properly space out the inner tubing string
(125) prior to cutting the inner coiled tubing and installing the
slip bowl (175), as is well understood in the art.
[0071] After the inner string (125) has been landed, the severed
coiled tubing (125A) is removed from the surface equipment. The
master valve (35) is closed and the BOP (40), work window (45),
lubricator (50), stuffing box (55), and injector head (60) are
nippled down and removed. If a dummy carrier has been installed in
the jet pump assembly, a working carrier may be pumped down and
installed after the dummy carrier has been reverse circulated out
of the well.
[0072] When the jet pump assembly is activated by fluid flow pumped
down the inner coiled tubing (125), water will be sucked into the
stinger (155) and on to the jet pump assembly where it will be
pumped out of the hole. In a preferred embodiment, a strainer
serves as the stinger (155) and prevents large debris from plugging
the jet pump assembly. The strainer may be a sucker rod strainer, a
wire wrapped screen, a perforated/slotted pipe, or any other
suitable means that has been effectively miniaturized to fit
through the outer coiled tubing string (25).
[0073] In the event the concentric coiled tubing string needs to be
removed from the wellbore, it is still necessary to maintain the
mechanical flow barriers. In one embodiment, before pulling the
inner string (125), a working carrier may be reverse circulated out
of the jet pump assembly and a dummy carrier (not shown) circulated
down and installed. Alternatively, a dummy carrier may be installed
via wireline in the jet pump assembly. The dummy carrier will serve
as a mechanical barrier for the inner string (125) as it is removed
from the well. A wireline plug (175), shown in FIG. 14, may then be
run into the outer coiled tubing (25) and set in a nipple profile
(83). Unlike the aforementioned flapper (87), the wireline plug
(175) may be tested with pressure to make sure it is holding. Once
the wireline plug (175) is set and tested, the outer string (25)
may then be removed from the well.
[0074] While preferred embodiments of the apparatus and methods
have been discussed for purposes of this disclosure, numerous
changes in the construction, installation, and function of the jet
pump apparatus and concentric coiled tubing string may be made by
those skilled in the art. All such changes are encompassed within
the scope and spirit of the following claims.
* * * * *