U.S. patent application number 12/363474 was filed with the patent office on 2011-03-17 for hydraulically driven downhole pump using multi-channel coiled tubing.
This patent application is currently assigned to CONOCOPHILLIPS COMPANY. Invention is credited to Curtis G. Blount, Thomas E. Nations, John C. Patterson, Dennis R. Wilson.
Application Number | 20110061873 12/363474 |
Document ID | / |
Family ID | 40986168 |
Filed Date | 2011-03-17 |
United States Patent
Application |
20110061873 |
Kind Code |
A1 |
Patterson; John C. ; et
al. |
March 17, 2011 |
Hydraulically Driven Downhole Pump Using Multi-Channel Coiled
Tubing
Abstract
This invention relates to a coiled tubing installed and operated
hydraulically driven downhole pump for hydrocarbon wells and
especially hydrocarbon gas wells that are prone to produce fluids
that choke gas production. The hydraulically driven downhole pump
is driven by a closed loop surface positioned hydraulic power
system. Should the hydraulically driven downhole pump become
inoperative, it may be quickly retrieved and immediately replaced
using a coiled tubing unit as compared to a workover rig. A coiled
tubing unit is able to pull the coiled tubing string and re-install
the string quite rapidly because the coiled tubing does not have
joints that need to be disassembled or reconnected. The manpower
needs and costs for replacement are considerably less and lost
production of the well is substantially reduced.
Inventors: |
Patterson; John C.;
(Cypress, TX) ; Nations; Thomas E.; (Katy, TX)
; Blount; Curtis G.; (Katy, TX) ; Wilson; Dennis
R.; (Aztec, NM) |
Assignee: |
CONOCOPHILLIPS COMPANY
Houston
TX
|
Family ID: |
40986168 |
Appl. No.: |
12/363474 |
Filed: |
January 30, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61030809 |
Feb 22, 2008 |
|
|
|
Current U.S.
Class: |
166/369 ;
417/65 |
Current CPC
Class: |
E21B 43/129
20130101 |
Class at
Publication: |
166/369 ;
417/65 |
International
Class: |
E21B 43/12 20060101
E21B043/12; E21B 43/00 20060101 E21B043/00 |
Claims
1. An apparatus for producing fluids in a wellbore wherein gas is
produced through one annular space and fluids are produced through
a separate space; wherein the apparatus comprises: a. casing in the
wellbore; b. production tubing within the casing; c. a
hydraulically driven downhole pump within the production tubing and
attached to the distal end of a multi-channel coiled tubing string
that extends to the surface of the borehole; d. a hydraulic power
unit disposed at the surface and connected to the multi-channel
coiled tubing string so as to provide high pressure hydraulic fluid
into a first channel within the multi-channel coiled tubing string
and receive hydraulic fluid through a second channel within the
multi-channel coiled tubing string and together define a closed
loop hydraulic fluid system where hydraulic fluid is not mixed with
production fluids; and e. whereby a fluid production space is
defined within the production tubing and outside the multi-channel
coiltubing driven by the hydraulically driven downhole pump and
further whereby a gas production space is defined outside of the
production tubing and within the casing.
2. The apparatus according to claim 1, wherein the hydraulic power
unit includes a power take off device and for a gas compressor for
compressing the produced gas from the well site using a single
power unit.
3. The apparatus according to claim 1, wherein the hydraulic power
unit provides a continuous supply of high pressure hydraulic fluid
through said first channel of said coiled tubing string and
continuously receives lower pressure hydraulic fluid from said
second channel of said coiled tubing string into a reservoir.
4. The apparatus according to claim 1, wherein the multi-channel
coiled tubing string comprises two coiled tubing strings, one
concentrically located within another defining the first channel to
be axially within the inner coiled tubing string and the second
channel being the annular space outside of the inner coiled tubing
string and within the outer coiled tubing string.
5. The apparatus according to claim 1, wherein the multi-channel
coiled tubing string comprises an outer wall and a continuous web
section within the outer wall dividing the interior of the coiled
tubing string into two separate and distinct side-by-side
channels.
6. The apparatus according to claim 1, further including a standing
valve and seal assembly by which accepts the hydraulically driven
downhole pump and which provides well control during the insertion
and pulling and replacing of the hydraulically driven downhole
pump.
7. The apparatus according to claim 1, further including a heat
transfer device for heating the hydraulic fluid and thereby heat
the wellbore to prevent ice from forming and maintain any
paraffinic hydrocarbons above their cloud point.
8. The apparatus according to claim 7, wherein the heat transfer
device is a liquid/liquid heat exchanger where coolant from an
internal combustion engine that is used to drive the hydraulic
power unit is arranged to provide some of the heat in the coolant
to the hydraulic fluid.
9. A process for co-producing hydrocarbon gas and produced fluids
separately from a wellbore wherein the process comprises: a.
providing casing in the wellbore; b. inserting production tubing
within the casing; c. attaching a hydraulically driven downhole
pump to the distal end of a multi-channel coiled tubing string; d.
inserting the hydraulically driven downhole pump and multi-channel
coiled tubing string into the production tubing within the
wellbore; e. providing high pressure hydraulic fluid from a
hydraulic power unit to the distal end of the multi-channel coiled
tubing string so that high pressure hydraulic fluid is delivered by
the hydraulic power unit and to the downhole hydraulically driven
pump and returns to the hydraulic power unit through a second
channel in the multi-channel coiled tubing string thereby pumping
produced fluid in the wellbore up through the annular space within
the production tubing but outside the multi-channel coiled tubing
string while hydrocarbon gas is produced in the annular space
within the casing but outside the production string.
10. The process according to claim 9, further including the step of
providing power to the hydraulic power unit and providing
compression of the produced gas from a common power source for the
well site.
11. The process according to claim 9, wherein the step of providing
high pressure hydraulic fluid from the power unit further comprises
providing a continuous supply of high pressure hydraulic fluid
through said first channel of said coiled tubing string and
continuously receives lower pressure hydraulic fluid from said
second channel of said coiled tubing string into a reservoir.
12. The process according to claim 9, wherein the step of providing
a multi-channel coiled tubing string comprises providing a
multi-channel coiled tubing string having an outer wall and a
continuous web section within the outer wall dividing the interior
of the coiled tubing string into two separate and distinct,
side-by-side channels.
13. The process according to claim 9, wherein the step of providing
a multi-channel coiled tubing string further comprises providing
two coiled tubing strings, one concentrically located within
another so that the first channel is axially within the inner
coiled tubing string and the second channel in the annular space
outside of the inner coiled tubing string and inside of the outer
coiled tubing string.
14. The process according to claim 13, wherein the process further
includes the steps of installing the outer coiled tubing string
into the production tubing and then installing the inner coiled
tubing string into the outer coiled tubing string, connecting the
two coiled tubing strings together with a pump adaptor attached to
the outer coiled tubing string and a stinger attached to the inner
coiled tubing string and suited for stinging into the pump
adaptor.
15. The process according to claim 9, further including the step of
heating the hydraulic power fluid to thereby heat the wellbore and
prevent the formation of ice and maintain any paraffinic
hydrocarbons to be above their cloud point.
16. The process according to claim 15, where the step of heating
the hydraulic power fluid to comprises heating the hydraulic fluid
using heat from an internal combustion engine by providing coolant
from the internal combustion engine into heat exchange contact with
the hydraulic fluid.
17. An apparatus for producing fluids in a wellbore wherein gas is
produced through one annular space and fluids are produced through
a separate space; wherein the apparatus comprises: a. casing in the
wellbore; b. a hydraulically driven downhole pump within the casing
and attached to the distal end of a multi-channel coiled tubing
string that extends to the surface of the borehole; c. a hydraulic
power unit disposed at the surface and connected to the
multi-channel coiled tubing string so as to provide high pressure
hydraulic fluid into a first channel within the multi-channel
coiled tubing string and receive hydraulic fluid through a second
channel within the multi-channel coiled tubing string and together
define a closed loop hydraulic fluid system where hydraulic fluid
is not mixed with production fluids; and d. a third channel for the
production of fluid from the hydraulically driven downhole pump
separate from the production path of gas production.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to U.S. Provisional
Application No. 61/030,809, filed Feb. 22, 2008.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] None
FIELD OF THE INVENTION
[0003] This invention relates to pumping fluids from the bottom of
a wellhole.
BACKGROUND OF THE INVENTION
[0004] In natural gas wells, it is common for fluids such as water
to be produced that if allowed to remain in the wellhole, will
choke the production of natural gas. Pumping such fluids to the
surface increases the gas productivity of such wells and increases
the profits of the well owners. However, most gas wells are not
straight or vertical. Many have deviations and it is common to
drill substantial deviations to increase well contact with the
productive zone. Another reason for directional drilling is to
reduce the environmental impact of oil and gas production by
drilling from existing well or drilling sites with the aim of
reaching out underground to new hydrocarbon bearing zones to get
access to additional reserves with a minimal footprint. Such
deviated wells make pumping with a pump driven by a reciprocating
rod or rotating shaft unattractive as the casing is likely to be
worn and breached over time. Moreover, the frictional losses
increase the horsepower requirements and increases costs of
production.
[0005] Another challenge with pumping wells is the cost of
repairing or replacing a pump. With reciprocating rod pumps,
electrically driven pumps and hydraulically driven pumps, the
problems with friction and deviated wells may be avoided, but even
these types of pumps suffer problems and must be removed and
replaced. Typically, when a problem occurs with a well, a workover
rig is required to pull the pump back to the surface. It is not
uncommon for a workover rig to take four days to pull a pump and
then insert the repaired or replacement pump back into location.
This does not take into account the availability of a workover rig.
As such, the well may be offline for a week or more and seriously
cut into the profitability of the gas well.
SUMMARY OF THE INVENTION
[0006] The present invention provides an arrangement for An
apparatus for producing fluids in a wellbore wherein gas is
produced through one annular space and fluids are produced through
a separate space; wherein the apparatus comprises casing in the
wellbore and production tubing within the casing. A hydraulically
driven downhole pump is located within the production tubing and
attached to the distal end of a multi-channel coiled tubing string
that extends to the surface of the borehole. A hydraulic power unit
disposed at the surface and connected to the multi-channel coiled
tubing string is arranged to provide high pressure hydraulic fluid
into a first channel within the multi-channel coiled tubing string
and receive hydraulic fluid through a second channel within the
multi-channel coiled tubing string and together define a closed
loop hydraulic fluid system where hydraulic fluid is not mixed with
production fluids. With this arrangement a fluid production space
is defined within the production tubing and outside the
multi-channel coiled tubing driven by the hydraulically driven
downhole pump and further whereby a gas production space is defined
outside of the production tubing and within the casing.
[0007] A process for co-producing hydrocarbon gas and produced
fluids separately from a wellbore wherein the process comprises
providing casing in the wellbore and inserting production tubing
within the casing. A hydraulically driven downhole pump is attached
to the distal end of a multi-channel coiled tubing string and then
inserted into the production tubing within the wellbore. The
process further includes providing high pressure hydraulic fluid
from a hydraulic power unit to the distal end of the multi-channel
coiled tubing string so that high pressure hydraulic fluid is
delivered by the hydraulic power unit and to the downhole
hydraulically driven pump and returns to the hydraulic power unit
through a second channel in the multi-channel coiled tubing string
thereby pumping produced fluid in the wellbore up through the
annular space within the production tubing but outside the
multi-channel coiled tubing string while hydrocarbon gas is
produced in the annular space within the casing but outside the
production string.
[0008] In a further preferred arrangement of the invention, the
process includes assembling the multi-channel coiled tubing as a
concentric coiled tubing string with fittings to seal the bottom
and top ends for pumping hydraulic fluid in a closed loop while
also providing simpler processes for pulling and replacing the pump
in the event of pump failure and other downhole issues.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The invention, together with further advantages thereof, may
best be understood by reference to the following description taken
in conjunction with the accompanying drawings in which:
[0010] FIG. 1 is a fragmentary view of the coiled tubing string
connected to a hydraulic pump illustrating the gas production
annular space, the liquid production annular space and the closed
hydraulic system for driving the hydraulic pump;
[0011] FIG. 2 is a somewhat schematic perspective view of a
production skid at the surface adjacent a hydrocarbon producing
well;
[0012] FIG. 3 is a cross section of a first embodiment of a coiled
tubing string for use with the present invention;
[0013] FIG. 4 is a cross section of a second embodiment of a coiled
tubing string that is suitable for use with the present
invention;
[0014] FIG. 5 is a perspective view of the pump adaptor;
[0015] FIG. 6 is a perspective view of the return fitting;
[0016] FIG. 7 is a perspective view of the stinger;
[0017] FIG. 8 is an elevation view of the top end coiled tubing
fixture; and
[0018] FIG. 9 is a schematic top view of an alternative embodiment
of a production skid at the surface adjacent a hydrocarbon
producing well.
DETAILED DESCRIPTION OF THE INVENTION
[0019] This invention relates to producing water and other fluids
in a gas well where the fluids must be produced to avoid
restricting the production of hydrocarbon gas. As best seen in FIG.
1, the invention is generally indicated by the numeral 10. The
invention 10 is positioned within a well that has been drilled or
bored into the ground and in which a string of casing 12 has been
inserted. It is conventional for the casing to extend below the
surface S down through the ground into a production zone 14. The
production zone 14 is where the gas and fluids permeate toward the
casing 12 and enters the production well 15 at the base of the
casing 12. Fractures (not indicated) are created in the casing 12
in the proximity of the production zone 14 so that, according to
conventional procedures, the gas permeates from the production zone
14 and into the production well 15.
[0020] Within the casing 12 is positioned a production tubing 18
through which any fluids may be produced to the surface. The gas in
the production well 15 is produced through the annular space
between the outside of the production tubing 18 and the inside of
casing 15 as indicated by arrows 19. The gas is directed through a
valve 21 and piping 22 to a production meter and a gathering system
and perhaps other post production treatments before it is conveyed
to market.
[0021] Near the base of the production tubing 18 is a hydraulically
driven downhole pump 30. Various hydraulic pump styles will be
useful with the present invention, however, it is preferred to use
a hydraulic diaphragm pump also called a hydraulic diaphragm insert
pump or HDI pump. The preferred HDI pump is available from
SmithLift, a division of Smith Industries, Inc. The hydraulically
driven downhole pump 30 is arranged at the base of the production
tubing 18 so as to draw water and other produced fluids that settle
in the production well 15 up into the production tubing 18 through
a nipple 24 at the base of the production tubing 18 and up through
standing valve 25. As is conventional, once the fluids pass through
the nipple 24 and standing valve 25 into production tubing 18, the
fluids are not permitted to drain back into the production well 15.
In the event that the hydraulically driven downhole pump 30 is
pulled out of the production tubing 18, water is allowed to fill
the space it occupied and the standing valve 25 maintains the fluid
level within the production tubing 18. Having fluid in the
production tubing provides head pressure to maintain well control.
In operation, the hydraulically driven downhole pump 30 pushes the
fluids up through the production tubing 18 to the surface as
indicated by arrows 31 until the fluids are collected through valve
33 and piping 34. It is not uncommon for the fluids to include
valuable hydrocarbon fluids so their collection may be quite
profitable. While any water may require treatment to separate
valuable fluids and may be disposed of by re-injection or other
environmentally acceptable disposal means, there is another
potential problem if the hydrocarbon fluids include amounts of
paraffins. At lower temperatures, the paraffins may form waxy
deposits in the production tubing 18 that may restrict or plug the
annular space and impede the removal of the fluids from the gas
production zone 14.
[0022] Within the production tubing 18 is a multi-channel coiled
tubing string 50. In the preferred embodiment and referring to FIG.
3, the multi-channel coiled tubing string 50 includes a concentric
coiled tubing string 51 having a smaller diameter inserted within a
larger diameter coiled tubing string 52. With this concentric
coiled tubing string, axial channel 54 is defined which is separate
from annular channel 55. For comparison, referring to FIG. 4 is a
second embodiment of a coiled tubing string 150 having side by side
channels defined by the outer wall 151 and a continuous web section
152 that separates a first channel 154 from a second channel 155.
Other structural arrangements for coiled tubing having multiple
channels would also be useful with the present invention. With
multiple channels, the third and subsequent channel may be used for
pump or other well control or may be adapted to carry the produced
liquids to the surface through an additional channel
[0023] Turning back to FIG. 1, the hydraulically driven downhole
pump 30 is connected to the base or distal end of coiled tubing
string 50 so as to be inserted into position by a coiled tubing
unit as the coiled tubing string 50 is inserted into the production
tubing 18 of the wellbore. A coiled tubing unit is generally
smaller, less expensive and is operated with fewer people than a
workover rig. With no joints to assemble or disassemble, coiled
tubing may be quickly inserted into a borehole, withdrawn and
re-inserted. With the hydraulically driven downhole pump 30
attached to the bottom or distal end of the coiled tubing string
50, the pump is also quickly and easily installed, retrieved and
replaced as compared to the same job being performed by a workover
rig that uses thirty foot segments of pipe or rod connected by
threaded joints at each end.
[0024] In operation, the hydraulically driven downhole pump 30 is
driven by a hydraulic drive unit generally indicated by the numeral
60 at the surface. Hydraulic drive unit 60 includes a hydraulic
power unit 62 sometimes called a hydraulic pump but to avoid
confusion with pump 30 the term "hydraulic power unit" is employed.
The hydraulic power unit 62 is of conventional design that draws
hydraulic fluid from reservoir 64 and delivers high pressure
hydraulic fluid through tubing 66. Referring to FIG. 2, hydraulic
power unit 62 may be driven by an internal combustion engine 72 or
other suitable drive unit such as an electric motor. In the field,
it is conventional to use whatever power source is available and
cost effective. Mounting equipment for use in the field on a skid
unit such as skid unit 74 is well known. As such, the internal
combustion engine 72 is shown mounted on a skid unit 74 along with
hydraulic power unit 62.
[0025] Referring back to FIG. 1, the hydraulic fluid is directed
into the first axial channel 54 to provide high pressure fluid to
the hydraulically driven downhole pump 30 at the distal end of the
coiled tubing string 50. The high pressure hydraulic fluid is
preferably provided continuously at a relative constant pressure as
compared to a push/pull stroke from the surface. The high pressure
hydraulic fluid may run over vanes to cause rotational motion of
the pump 30 and therefore pumping of the fluid or, as preferred,
the high pressure hydraulic fluid is directed through valves in the
hydraulic pump that causes positive displacement of the fluids in
the annular space inside the production tubing 18 and outside the
coiled tubing string 50.
[0026] As is known in the pumping arts, a positive displacement
pump will cycle from drawing fluid into a chamber through one or
more one-way valves in one stroke and then push the fluid out of
the chamber through a reverse stroke through one or more one-way
valves that lead to the desired space for the fluid. The preferred
embodiment of the present invention seeks to take advantage of
known systems utilizing valving in the pump that allows the pump to
extend through a full stroke and then actuated by the completion of
the stroke and begin to use the source of high pressure to reverse
the stroke and cycle back and forth pushing fluids to the surface.
Considering the depth of some wells, having the valving to reverse
the stroke at the surface with the hydraulic power is not preferred
as delays from sensing the end of the stroke and over pressure
situations are likely to occur. Pump reliability is an issue with
pumps in wells and while the present invention is intended to help
minimize the cost of deploying and replacing pumps, anything to
improve the reliability of pumps improves the bottom line for the
well owner.
[0027] So in preferred operation, the high pressure hydraulic fluid
is directed down the axial channel 54 of the concentric coiled
tubing 50 and follows the path shown by arrow 56. The high pressure
hydraulic fluid is then used by the hydraulically driven downhole
pump 30 to drive fluids up the annular space outside the coiled
tubing 50 and inside the production tubing 18 to follow the path
indicated by the arrows 31. At the same time, the hydraulic fluid
used by the hydraulically driven downhole pump 30 flows back to the
surface in an annular channel 55 along a path indicated by arrows
57 and back to reservoir 64 through tubing 65. With the fluids
withdrawn from the production well 15, the gas production flows up
the annulus outside of the production tubing 18 and within the
casing 12 along a path indicated by arrows 19. It should be noted
that the hydraulic fluid is not permitted to mix with the
production fluids and that there are at least four distinct and
separate flow channels created within the casing 12 by the
production tubing 18 and the multi-channel coiled tubing 50. One
flow channel is downward and three are upward.
[0028] In another aspect of the present invention, as more
particularly shown in FIG. 2, the internal combustion engine 72 may
be used to drive other systems at the well. As shown, gas
compressor 82 is shown being driven by belt 75 along with hydraulic
power unit 62. Sharing the power source for different systems
reduces costs and improves the bottom line for marginal wells. In
addition, since multiple wells are being drilled from existing or
common drill sites, it is another aspect of the invention to
operate hydraulic pumps for several wells based on a common
internal combustion engine 72. In such an arrangement, the internal
combustion engine may be run continuously and the various demands
of different wells and compressing the produced gas from one or
more wells while the control systems may operate the various
hydraulic pumps on an intermittent basis.
[0029] In the preferred embodiment, the hydraulic fluid directed
down the axial channel 54 and back up the annular channel 55 of the
coiled tubing sting 50 comprises a water based biodegradable
hydraulic fluid that will cause little if any hazard if there is a
spill or leak. It certainly will be recognized by those skilled in
the art that any hydraulic fluid can be used to operate the
pump.
[0030] In the most preferred embodiment, concentric coiled tubing
string 50 comprises two coiled tubing strings. The first is a 3/4''
coiled tubing string (power-string) placed inside of a 11/2''
coiled tubing string (return-string). The high pressure hydraulic
fluid is pumped from the surface down the 3/4'' coiled tubing
string. The return fluid is directed up the annular channel 55
outside of the 3/4'' inner coiled tubing string 51 and the inside
of the 11/2'' outer coiled tubing string 52. The concentric coiled
tubing strings are sealed on bottom with a stinger and receiver
seal-assembly combination as are known. The concentric coiled
tubing strings are sealed at the surface with a combination of
fittings as are also known by those using coiled tubing. The
concentric coiled tubing, seal assembly and associated fittings
ensure that the hydraulic fluid is contained within the closed-loop
throughout the pumping process.
[0031] Concentric coiled tubing is not new. However, it is not
generally available from coiled tubing manufacturers or vendors.
The inventors have developed a new and inventive procedure to
insert a smaller diameter coiled tubing string into a larger coiled
tubing string and, if necessary, to easily remove it. The process
begins onsite at the well with production tubing 18 already
installed within the casing 12. Referring to FIGS. 5 and 6, return
fitting 71 is attached to the bottom end of the outer coiled tubing
string 52 while the outer coiled tubing string is still wound on
the coiled tubing unit. Preferably, the end 72 is welded to the
bottom end of the outer coiled tubing string 52. Pump adaptor 81 is
connected by screw threads 84 into screw threads 74 of return
fitting 71. Upper receiver end 85 of pump adaptor 81 extends up
inside returning fitting 71 so that the outer surface of the upper
receiver end 85 forms an annular space within the inner surface 73
of return fitting 71. The connection between the return fitting 71
and the pump adaptor 81 is preferably sealed by suitable o-rings
87. A cap (not shown) is attached over screw threads 88 and sealed
by o-ring 89 and the entire length of the coiled tubing string 52
is filled with a suitable well control fluid.
[0032] The outer coiled tubing string 52 is then run into the
production tubing 18 until the cap comes into contact with the
standing valve 25. The outer coiled tubing string 52 is then cut to
length and the coiled tubing unit associated with the larger
diameter outer coiled tubing string 52 is moved away from the well.
The smaller diameter inner coiled tubing string 51, still wound on
a coiled tubing unit spool, is provided with stinger 91 attached to
the bottom end thereof. Preferably, the top end 92 of stinger 91 is
welded onto the end of the smaller diameter inner coiled tubing
string and the coiled tubing unit is arranged to then insert the
smaller diameter inner coiled tubing string 51 into the outer
coiled tubing string disposed within the production tubing 18.
Tapered end 93 of stinger 91 eventually stings into the open end of
the pump adaptor 81 and seal against the interior of the upper end
thereof with o-rings 94. At the top end of the coiled tubing
strings, a top end coiled tubing fixture 111 shown in FIG. 8 is
attached to the outer coiled tubing string 52. The top end coiled
tubing fixture 111 comprises two components that are connected by
screw threads. The first component 112 comprises a first end 113
for insertion into the outer coiled tubing string 52. The first end
113 includes a longitudinal outer surface groove 114 to align with
any welding seam in the coiled tubing. The first component 112 is
intended to have a tight fit with the outer coiled tubing string
and may be hammered to fully seat the collar 115 to the end of the
outer coiled tubing string 52. Once in place, the first component
112 of the fixture is welded to the outer coiled tubing string 52
so as to seal the two together. The second component 121 attaches
to the first component 112 by screwing the threads 122 into the
threads 116 of the first component and the free end is configured
with radial grooves 124 and o-rings 125 for having a tail section
(not shown) of coiled tubing crimped thereon for pulling the
concentric coiled tubing out of the well on wound onto coiled
tubing unit spool. With this arrangement, each time the coiled
tubing and pump are pulled and re-installed, the length of the two
coiled tubing strings are preserved.
[0033] The first coiled tubing unit is then moved into position
over the well to connect to the upper end of the second component
121 of top end coiled tubing fixture 111 to withdraw both coiled
tubing strings 51 and 52. In another aspect of the present
invention, it is not uncommon for scale and other surface debris to
become loosened from the inner surface of both strings of coiled
tubing. As such, the debris may pose a risk to the long term
operation of the hydraulic pump and it is preferred that such
debris is removed from the systems. In respect of this concern,
once the two strings of coiled tubing are installed into the well
and then pulled in preparation for installing the hydraulic pump,
the bottom end of the two strings are opened by the removal of the
cap that was attached to the end of the pump adaptor at threads 88.
Cleaning fluid may be pumped through the coiled tubing while wound
on the coiled tubing unit and filtered and recycled until the
operator is satisfied that any loosened particles have been washed
out of the system. With this simple step, it is anticipated that
operational availability of the pump has been extended.
[0034] The hydraulically driven downhole pump 30 is then attached
to the screw threads 88 so that the hydraulic fluid inlet of the
pump is connected to fitting 101 and the hydraulic fluid outlet
flow passes through the pump adaptor 81 and into the annular
channel 55 through holes 82. Holes (not shown) are positioned at
the bottom of the pump adaptor 81 between the screw threads 88 and
fitting 101 which are in fluid communication with holes 81 so that
low pressure hydraulic fluid then passes up through the annular
channel 55. Once the hydraulically driven downhole pump 30 is
attached to the end of the concentric coiled tubing strings 51 and
52, and the string is inserted into the production tubing so that
the hydraulically driven downhole pump 30 engages with standing
seal 25, the coiled tubing strings 51 and 52 may also be cut to
length and provided with fittings for connection to tubing 65 and
66.
[0035] As noted above, a particular advantage of the present
invention is that a single coiled tubing unit may quickly pull the
multi-channel coiled tubing string out of the well with the pump
attached. However, if the pump or coiled tubing string is stuck or
gets stuck while being pulled, a new problem emerges. When it is
clear that the coiled tubing will break under the tension of the
unit against the "stuck" pump, the coiled tubing can be withdrawn
by an inventive technique to minimize the hassle and time involved
with recovering the pump and getting the well back into service. If
the tubing is cut off at the surface and a workover rig is called
in to withdraw the production tubing, additional coiled tubing will
have to be cut as each joint of production tubing is broken apart.
With a production tubing string being many thousands of feet,
significant additional time could be wasted cutting the coiled
tubing or worse yet, cutting two strings concentrically disposed.
In the inventive process, the inner coiled tubing string 51 is
withdrawn by un-stinging the stinger 91 from pump adaptor 81. Then
a wireline free point tool may be inserted into the outer tubing.
The wireline free point tool is able to measure minute stretching
in the tubing and by sequentially pulling and releasing the tubing
can determine "free point" or the lowest point at which the tubing
is "not stuck". Weatherford International Ltd is a well known oil
field services company that provides such free point tools and
services. The free point tool is removed and a chemical or
explosive cutting tool is run down into the outer coiled tubing
string to a point just above free point to cut the outer coiled
tubing string 52 so that the coiled tubing unit can pull the free
portion of the coiled tubing string out of the production tubing.
Then the workover rig can then pull the production tubing 18 and
only deal with the length of stuck coiled tubing attached to the
pump 30. Once the pump is recovered, the production tubing 18 and
pump 30 along with the multi-channel coiled tubing may be
re-installed in the well to return it to productive service.
[0036] In another aspect of the present invention, wells that
produce a lot of gas and fluid generally remain fairly warm as the
fluids entering the wellbore retain the heat energy of the
formation. However, in circumstances where small amounts of gas and
fluids are produced, cool nights may allow water to freeze inside
the well bore and for paraffinic hydrocarbons to congeal as wax. In
one embodiment of the invention, such problems can be addressed by
an arrangement shown in FIG. 9. A skid unit 274, which is similar
to skid unit 74 in FIG. 2, is illustrated with an internal
combustion engine 272 to drive the hydraulic power unit 262 and a
gas compressor 282 by belts 275A and 275B, respectively. The
internal combustion engine, as is conventional, is cooled by a
fluid jacket in which coolant is pumped through and into a radiator
276. However, in the present invention, the coolant is first
directed to a liquid/liquid heat exchanger 267 via conduit 277
where some of the engine heat is transferred to the hydraulic fluid
used to drive the hydraulically driven downhole pump 30 at the base
of the well. Coolant exits heat exchanger 267 via conduit 278 and
enters radiator 276 and eventually returns to the engine 272. In
FIG. 9, the hydraulic fluid is driven by hydraulic power unit 262
through conduit 266 to liquid/liquid heat exchanger 267. In the
heat exchanger 267, heat is transferred from the engine coolant to
the hydraulic fluid and the heated hydraulic fluid is then carried
to the well via conduit 269. The warm hydraulic fluid then
transfers some of its heat to the well to prevent or at least
reduce the likelihood of ice forming downhole and prevent wax
buildup by keeping any paraffins in the liquid above their cloud
point temperature. The temperature of the hydraulic fluid may be
maintained to be sufficiently above ambient air temperature with
little operating cost and will maintain the wellbore and pipes
therein well above freezing and above the cloud point of any
paraffin in a gas well. It should be understood that it is
preferred for the heat exchanger 267 to heat the hydraulic fluid
prior to entering the well so that the hydraulic is warmest as it
enters the well and is coolest when entering the hydraulic power
unit 262.
[0037] Finally, the scope of protection for this invention is not
limited by the description set out above, but is only limited by
the claims which follow. That scope of the invention is intended to
include all equivalents of the subject matter of the claims. Each
and every claim is incorporated into the specification as an
embodiment of the present invention. Thus, the claims are part of
the description and are a further description and are in addition
to the preferred embodiments of the present invention. The
discussion of any reference is not an admission that it is prior
art to the present invention, especially any reference that may
have a publication date after the priority date of this
application.
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