U.S. patent application number 10/730616 was filed with the patent office on 2005-06-09 for downhole oilfield erosion protection of a jet pump throat by operating the jet pump in cavitation mode.
Invention is credited to Lambert, Mitchell Darwin, Northeast, Chad A..
Application Number | 20050121191 10/730616 |
Document ID | / |
Family ID | 34634208 |
Filed Date | 2005-06-09 |
United States Patent
Application |
20050121191 |
Kind Code |
A1 |
Lambert, Mitchell Darwin ;
et al. |
June 9, 2005 |
Downhole oilfield erosion protection of a jet pump throat by
operating the jet pump in cavitation mode
Abstract
A method of improving erosion performance (decreasing the
erosion) of components--such as a throat, a nozzle, or a
diffuser--for a downhole tool used for cleaning a wellbore is
disclosed.
Inventors: |
Lambert, Mitchell Darwin;
(Calgary, CA) ; Northeast, Chad A.; (Calgary,
CA) |
Correspondence
Address: |
HOWREY SIMON ARNOLD & WHITE LLP
c/o IP DOCKETING DEPARTMENT
2941 FAIRVIEW PARK DRIVE, SUITE 200
FALLS CHURCH
VA
22042-7195
US
|
Family ID: |
34634208 |
Appl. No.: |
10/730616 |
Filed: |
December 8, 2003 |
Current U.S.
Class: |
166/265 ;
166/369 |
Current CPC
Class: |
E21B 37/00 20130101 |
Class at
Publication: |
166/265 ;
166/369 |
International
Class: |
E21B 043/34 |
Claims
What is claimed is:
1. A method of protecting a jet pump throat from downhole erosion
comprising the steps of: positioning a jet pump in a wellbore, the
jet pump comprising a nozzle and a throat; pumping a power fluid
through the jet pump at a sufficient velocity to cause the power
fluid pressure in the area between the nozzle and throat to be less
than or equal to the power fluid vapor pressure; and drawing
solids-ladened wellbore fluid into the jet pump and mixing the
wellbore fluid with the power fluid.
2. The method of claim I further comprising mixing the wellbore
fluid and power fluid while the fluid pressure is less than or
equal to the power fluid vapor pressure.
3. The method of claim 1 further comprising pumping the power fluid
through the jet pump at a sufficient velocity to cause the power
fluid pressure in the throat to be less than or equal to the power
fluid vapor pressure.
4. The method of claim 1 further comprising transporting the
mixture of power fluid and solids-ladened wellbore fluid through
the throat of the jet pump and out of the wellbore.
5. The method of claim 1 whereby the jet pump is positioned in the
wellbore by attaching the jet pump to a coil-in-coil tubing string
and running the jet pump on the coil-in-coil tubing into the
wellbore.
6. The method of claim 5 further comprising delivering the power
fluid to the jet pump via the center tubing of a coil-in-coil
tubing string.
7. The method of claim 5 further comprising returning the mixture
of power fluid and solids-laden wellbore fluid to the surface via
the coil tubing-coil tubing annulus.
8. The method of claim 1 wherein the power fluid pressure at the
nozzle exit is about absolute zero.
9. The method of claim 1 wherein the power fluid is selected from
brine, water, friction reduced water, gelled water, diesel, or
hydraulic oil.
10. A method of protecting a jet pump throat from downhole erosion
comprising the steps of: providing a jet pump in a wellbore, the
jet pump comprising a nozzle, one or more well fluid inlet ports,
and a throat; and pumping a power fluid through the jet pump at a
sufficient velocity to create cavitation vapor bubbles in the power
fluid in the throat; and drawing solids-ladened wellbore fluid
through the well fluid inlet ports and mixing the wellbore fluid
with the power fluid.
11. The method of claim 10 further comprising mixing the cavitation
vapor bubbles in the power fluid with the wellbore fluid.
12. The method of claim 10 further comprising pumping the power
fluid through the jet pump at a sufficient velocity to create
cavitation vapor bubbles in the area between the nozzle and
throat.
13. The method of claim 10 further comprising transporting the
mixture of power fluid and solids-ladened wellbore fluid through
the throat of the jet pump and out of the wellbore.
14. The method of claim 10 wherein the power fluid is selected from
brine, water, friction reduced water, gelled water, diesel, or
hydraulic oil.
15. The method of claim 10 further comprising attaching the jet
pump to a coil-in-coil tubing string and positioning the jet pump
at a desired location in the wellbore.
16. The method of claim 10 further comprising delivering the power
fluid to the jet pump via the center tubing of a coil-in-coil
tubing string.
17. The method of claim 16 further comprising pumping the fluid
mixture to the surface via the coil tubing-coil tubing annulus.
18. The method of claim 10 wherein the power fluid pressure at the
nozzle exit is about absolute zero.
19. A method of protecting a jet pump throat from downhole erosion
comprising the steps of: positioning a jet pump in a wellbore, the
jet pump comprising a nozzle and a throat; pumping a power fluid
through the jet pump at a sufficient velocity to cause the suction
pressure in the area between the nozzle and throat to be less than
or equal to the power fluid vapor pressure; drawing solids-ladened
wellbore fluid into the jet pump and mixing the wellbore fluid with
the power fluid; and transporting the mixture of fluid out of the
wellbore.
20. A method of removing solids from a wellbore comprising the
steps of: positioning a jet pump in a wellbore, the jet pump
comprising a nozzle, a fluid inlet port and a throat; pumping a
fluid through the jet pump at a sufficient velocity to cause the
power fluid pressure in the area between the nozzle and throat to
be less than or equal to the power fluid vapor pressure; and
drawing solids-ladened wellbore fluid into the jet pump through the
fluid inlet port and mixing the wellbore fluid with the power
fluid.
21. The method of claim 20 further comprising mixing the wellbore
fluid and power fluid while the fluid pressure is less than or
equal to the power fluid vapor pressure.
22. The method of claim 20 further comprising pumping the power
fluid through the jet pump at a sufficient velocity to cause the
power fluid pressure in the throat to be less than or equal to the
power fluid vapor pressure.
23. The method of claim 20 further comprising transporting the
mixture of power fluid and solids-ladened wellbore fluid through
the throat of the jet pump and out of the wellbore.
24. The method of claim 20 whereby the jet pump is positioned in
the wellbore by attaching the jet pump to a coil-in-coil tubing
string and running the jet pump on the coil-in-coil tubing into the
wellbore.
25. The method of claim 24 further comprising delivering the power
fluid to the jet pump via the center tubing of a coil-in-coil
tubing string.
26. The method of claim 25 further comprising pumping the fluid
mixture to the surface in the coil tubing-coil tubing annulus.
27. The method of claim 20 where the jet pump is operated at a
suction pressure of about absolute zero.
28. A method of removing solids from a wellbore comprising the
steps of: providing a jet pump in a wellbore, the jet pump
comprising a nozzle, one or more well fluid inlet ports, and a
throat; pumping a power fluid through the jet pump at a sufficient
velocity to create cavitation vapor bubbles in the power fluid in
the throat; and drawing solids from the wellbore through the well
fluid inlet ports and mixing the solids with the cavitation vapor
bubbles of the power fluid.
29. The method of claim 28 further comprising mixing the cavitation
vapor bubbles in the power fluid with the solids.
30. The method of claim 28 further comprising transporting the
mixture of power fluid and solids through the throat of the jet
pump and out of the wellbore.
31. The method of claim 28 further comprising attaching the jet
pump to a coil-in-coil tubing string and positioning the jet pump
at a desired location in the wellbore.
32. The method of claim 31 further comprising delivering the power
fluid to the jet pump via the center tubing of a coil-in-coil
tubing string.
33. The method of claim 32 further comprising transporting the
solids to the surface in the coil tubing-coil tubing annulus.
34. The method of claim 28 wherein the power fluid pressure at the
nozzle exit is about absolute zero.
35. A method of removing solids from a wellbore comprising the
steps of: pumping a power fluid to a downhole jet pump; drawing
wellbore solids into the jet pump and mixing the solids with the
power fluid while the fluid pressure of the power fluid is less
than or equal to the vapor pressure of the power fluid, and
transporting the solids-ladened mixture through the throat of the
jet pump and out of the wellbore.
36. The method of claim 35 whereby the jet pump is positioned in
the wellbore by attaching the jet pump to a coil-in-coil tubing
string and running the jet pump on the coil-in-coil tubing into the
wellbore.
37. The method of claim 36 further comprising delivering the power
fluid to the jet pump via the center tubing of a coil-in-coil
tubing string.
38. The method of claim 36 further comprising returning the mixture
of power fluid and solids to the surface via the coil tubing-coil
tubing annulus.
39. The method of claim 35 wherein the power fluid pressure at the
nozzle exit is about absolute zero.
40. The method of claim 35 wherein the power fluid is selected from
brine, water, friction reduced water, gelled water, diesel, or
hydraulic oil.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates to the cleaning of wellbores
in the field of oil and gas recovery. More particularly, this
invention relates to a device adapted to improve the erosion
performance of components utilized in the removal of solid
particulate matter from a well.
[0003] 2. Description of the Related Art
[0004] In the oil and gas industry, wellbores often become plugged
with sand, filter cake, or other hard particulate solids, which
need to be removed periodically to improve oil production. Prior
art methods for cleaning the wellbore and the removal of these
particulate solids include pumping a fluid from the surface to the
area to be cleaned. To effectively clean the solids from the
wellbore, the pumped fluids must return to surface, thereby
establishing circulation. Therefore, the bottom of the hole
circulating pressure must be high enough to support circulation but
low enough to prevent leak off into the reservoir. In addition, the
fluid velocity and rheological properties must support solids
suspension and transport.
[0005] It is known that the bottom hole pressure of a wellbore
declines as the reservoir matures, thereby complicating the
wellbore cleanout. For example, if the fluid being pumped into the
wellbore exits the work string (e.g., coiled tubing) at an
excessive pressure, the fluid may enter the formation instead of
returning to the surface with the sand particulates.
[0006] To overcome this problem, it is known to utilize
gasification (e.g., by the addition of nitrogen to the fluid) to
decrease the hydrostatic pressure in the wellbore. Thus, the fluid
may be pumped at reduced bottom hole pressures and circulation
through the wellbore may be restored to transport the particulates
to the surface. However, over time, the reservoir pressure may
decline to a point whereby gasification fails to result in
consistent circulation of fluid to effectively remove the
particulates.
[0007] Reverse circulating is another method commonly used to
increase the transport velocity of the fluid, especially when
employing small diameter tubing in large wellbores.
[0008] Yet another prior art method of removing the particulate
solids in the wellbore where the bottomhole circulating pressure is
a concern employs a jet pump. In the oil and gas industry, the jet
pump concept often is used to draw wellbore fluids into a closed
circuit hydraulic stream and return the wellbore fluid to the
surface. This procedure is generally performed in wells that have
very low bottom hole pressures, where the wellbore fluids cannot be
transported easily to the surface using other nitrogen lift
methodologies to lighten the hydrostatic head of the well. As
described in U.S. Pat. No. 5,033,545 to Sudol, issued Jul. 23,
1991, incorporated by reference herein in its entirety, the jet
pump is designed such that well fluids and solids enter the jet
pump at the bottom hole pressure (BHP). The jet pump then increases
the fluid pressure as it pumps the fluids up the work string with
the solid particulates entrained in the fluids. Thus circulation is
facilitated, as the circulation no longer depends on BHP alone.
[0009] FIG. 1 shows an exemplary prior art jet pump apparatus and
method for effectively removing particulates such as sand from
within a wellbore using production tubing. With reference to FIG.
1, a power fluid (arrows PF) is admitted under pressure to an
annular space between an outer pump casing 12 and the jet pump
device body 5. The annular space is closed off at its lower end. In
the general installation shown in FIG. 1, tubing string 8 is
attached at the top of the jet pump device body 5.
[0010] The jet pump includes one or several power fluid inlet ports
9 for admitting power fluid to the main nozzle I of the pump. The
main nozzle 1 discharges into a throat area 100 of the pump
assembly. The jet pump also includes a well fluids inlet port 7 for
admitting well fluids, or a mixture of fluids and solids, to fluid
passages in fluid communication with throat area 100. Power fluid,
under high pressure in the annular space, flows in the direction of
the arrows PF through the power fluid inlet port 9 into the main
nozzle 1. The main nozzle 1 jets the power fluid into the high
impact area 2 of the throat area 100.
[0011] Well fluids and solids flow under formation pressure through
the well fluids inlet port 7. The well fluids and solids then flow
in the direction of the arrows WF and into the high impact area 2
of the throat area 100. The well fluids and solids violently mix
with the power fluid in the throat area 100, particularly in the
high impact area 2. The returns (arrows R), comprised of power
fluid, well fluids and solids, then move through the throat to
production tubing 8, which extends to the production equipment at
the surface.
[0012] The jet pump also is particularly well-suited for use with a
coiled tubing string inside a coiled tubing string, or
"coil-in-coil tubing" (CCT), as described in U.S. Pat. No.
5,638,904 by Misselbrook et al., issued Jun. 17, 1997, incorporated
by reference herein in its entirety. The power fluid is pumped down
the inner coiled tubing string, and the return fluid stream, which
is comprised of a mixture of power fluid and well fluids and
solids, is taken up the coiled tubing-coiled tubing annulus.
[0013] The following is a simplified summary of the operation of
this prior art apparatus and method. With reference to FIG. 2, a
jet pump 5 is shown within a wellbore. The jet pump 5 is attached
to the bottom of CCT (not shown) via housing 6. In operation, the
jet pump closed circuit hydraulic stream generally begins with
power fluid, preferably water or brine, being injected into a pipe
with one end at the surface, preferably the inner coiled tubing
string (from left to right in FIG. 2). The power fluid then travels
down the pipe to the wellbore, goes through jet pump 5 to entrain
wellbore fluid, and finally returns to surface through an alternate
pipe or other closed path (pipe-pipe annulus), preferably the
coiled tubing-coiled tubing annulus.
[0014] The power fluid enters the lower end of jet pump 5 in the
direction shown by the arrows PF (from right to left in FIG. 2). As
the power fluid passes through nozzle 1 at nozzle exit 3, the
velocity of the power fluid increases significantly, creating a jet
stream. The jet pump itself acts like a venturi by taking the high
pressure power fluid (pumped from surface) and increasing the power
fluid's velocity via the nozzle 1. This increased velocity reduces
the pressure in the power fluid stream, which enables the low
pressure power fluid stream to draw in some portion of the well
fluids and solids (indicated by arrows WF) at well fluids inlet
port 7. The high-velocity combined fluid stream, which may contain
both fluids and solids, then enters the entrance end of the
diffuser or throat area 100. As the combined fluid stream (arrow R)
continues to travel upward through the throat area 100, the
diameter of the throat increases, the velocity of the fluid
decreases, and the fluid pressure increases. This recovered fluid
pressure drives the return fluid stream (arrow R) back to the
surface, overcoming the hydrostatic head.
[0015] If the jet pump is used to draw in sand or other well solids
as part of the wellbore fluids, severe erosion in the throat area
is observed, as the high velocity power fluid stream causes the
solids to impinge, scrape, and abrade the throat. As the solids
initially are drawn into the high velocity power fluid stream, the
velocity of the solids-ladened fluid does not yet match the
velocity of the power fluid stream. The solids-ladened fluids tend
to remain on the periphery of the power fluid stream, as shown in
FIG. 3, where they are more likely to have high-velocity impact
with the entrance section 10 of the throat 100. It has been
determined that in many applications, this causes excessive erosion
in the high impact area 2.
[0016] As a practical matter, poor erosion performance translates
into operational inefficiencies, as more frequent trips out of and
into hole are required to replace the excessively eroded
components.
[0017] Erosion of the downhole tools may be exasperated when
cleaning particulates from deeper wells. Deeper wells produce
additional challenges for the above-referenced procedure, as the
deeper wells have increased hydrostatic pressure and increase
friction pressure. Thus, the coiled tubing operation must
incorporate higher pump output pressure and higher jet velocities
in the nozzle and throat. For example, it is not uncommon for an
8600-foot well to have a bottom hole pressure of 1000 pounds per
square inch, causing the flow velocity through the throat to be
between 200 and 600 feet per second. These higher particle-laden
jet velocities increase the erosion rate in the throat.
[0018] It is also known in the prior art to decrease the erosion of
the components of downhole tools by manufacturing the components of
various materials, such as ceramics like Yttria stabilized
zirconia, or 6% submicron tungsten carbide. However, these prior
art methods fail to provide the desired level of erosion
performance and may not be economically feasible with deeper wells
(and the concomitant increased jetting velocities), as excessive
erosion still may result.
[0019] Thus, there is a need for a method for improving erosion
resistance (i.e., decreasing the erosion) of components used in the
cleaning of a wellbore, such as throats or diffusers utilized
downhole, when the components are exposed to high velocity
sand/fluid slurries. The method according to one embodiment of the
invention resists erosion associated with the high velocity jets of
solids-ladened fluid slurries generated when removing particulate
solids, such as sand, from the wellbore during well intervention or
workover. Further, the method of a preferred embodiment improves
longevity of components for downhole jet pumps and reduces the
relative frequency of trips in and out of hole for worn component
replacement.
SUMMARY OF THE INVENTION
[0020] The invention relates to methods of improving the erosion
resistance (i.e. decreasing the erosion) of components--for
example, throats and diffusers--of downhole tools used in the
removal of particulate solids from the wellbore.
[0021] The preferred method comprises operating a jet pump in a
condition known as cavitation when drawing in sand or other
wellbore solids, in order to decrease the erosive effect of drawing
the solids into the jet pump. When a jet pump is operated in
cavitation mode, the pumped power fluid stream velocity is
increased to a point where the power fluid pressure becomes very
low or near absolute zero--lower than the vapor pressure of the
fluid itself--where the fluid stream exits the nozzle. As the power
fluid exits the nozzle at this high velocity, the ultra low fluid
pressure causes the power fluid to create cavitation vapor bubbles,
which quickly form and then collapse as the power fluid is
recaptured by the throat. This action is extremely violent and
causes severe mixing of the power fluid and the wellbore fluids
being drawn in. The severe mixing action forces the sand particles
or other solids to be fully immersed in the fluid stream and
lessens the sand particles' exposure to the throat surface, thereby
reducing erosion of the throat.
[0022] One embodiment of the invention is directed to a method of
protecting a jet pump throat from downhole erosion comprising the
steps of positioning a jet pump in a wellbore, pumping a power
fluid through the jet pump at a sufficient velocity to cause the
power fluid pressure in the area between the nozzle and throat to
be less than or equal to the power fluid vapor pressure, and
drawing solids-ladened wellbore fluid into the jet pump and mixing
the wellbore fluid with the power fluid. Another embodiment
describes a method of removing solids from a wellbore comprising
the steps of providing a jet pump in a wellbore, pumping a power
fluid through the jet pump at a sufficient velocity to create
cavitation vapor bubbles in the power fluid in the throat, and
drawing solids from the wellbore through the well fluid inlet ports
and mixing the solids with the cavitation vapor bubbles of the
power fluid. Yet another embodiment describes a method of removing
solids from a wellbore comprising the steps of pumping a power
fluid to a downhole jet pump, drawing wellbore solids into the jet
pump and mixing the solids with the power fluid while the fluid
pressure of the power fluid is less than or equal to the vapor
pressure of the power fluid, and transporting the solids-ladened
mixture through the throat of the jet pump and out of the
wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] FIG. 1 shows a jet pump known in the prior art.
[0024] FIG. 2 shows a jet pump known in the prior art attached to
coil-in-coil tubing.
[0025] FIG. 3 illustrates the erosive effects of operating a jet
pump according to prior art methods.
[0026] FIG. 4 illustrates the operation of a jet pump in the
cavitation mode in accordance with one embodiment of the
invention.
[0027] While the invention is susceptible to various modifications
and alternative forms, a specific embodiment has been shown by way
of example in the drawings and will be described in detail herein.
However, it should be understood that the invention is not intended
to be limited to the particular forms disclosed. Rather, the
intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the invention
as defined by the appended claims.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0028] An illustrative embodiment of the invention is described
below as it might be employed in the oil and gas recovery
operation. In the interest of clarity, not all features of an
actual implementation are described in this specification. It will
of course be appreciated that in the development of any such actual
embodiment, numerous implementation-specific decisions must be made
to achieve the developers' specific goals, which will vary from one
implementation to another. Moreover, it will be appreciated that
such a development effort might be complex and time-consuming, but
would nevertheless be a routine undertaking for those of ordinary
skill in the art having the benefit of this disclosure. Further
aspects and advantages of the various embodiments of the invention
will become apparent from consideration of the following
description and drawings.
[0029] Embodiments of the invention will now be described with
reference to the accompanying FIG. 4. Dimensions described or shown
are intended for example only, as the invention disclosed herein is
not limited thereto. The invention is particularly well-suited for
use with a downhole jet pump attached to coil-in-coil tubing.
Referring to FIG. 4, the entrance section 10 of a throat 100 is
shown. The throat 100 may be comprised of any hardened material
suitable for downhole use, such as 6% cobalt tungsten carbide. Flow
of fluid during the cleanout procedure is from right to left (i.e.
the surface equipment is on the left, and the downhole obstruction
being removed from the wellbore is on the right). A main nozzle I
also is shown. By way of example, the inner diameter of the nozzle
preferably is in the range of about 0.060 inch to 0.125 inch.
[0030] In operation (as illustrated generally in FIGS. 1 and 2),
the high-velocity fluid with sand or other solid particulates
ultimately enters the entrance section 10 of the throat 100. As
shown schematically in FIG. 4, operating the jet pump in cavitation
mode causes solids to enter the center of the throat passage,
suspended in a mixture, and greatly reduces the degree of erosional
solids contact with the high impact area 2.
[0031] First, the power fluid (arrows PFY preferably brine but
alternatively water, friction reduced water, gelled water, diesel,
hydraulic oil, or the like-enters the nozzle 1 at high static
pressure and low velocity. Second, the power fluid (arrows PF) in a
preferred embodiment exits the nozzle 1 at the nozzle exit 3 at
high velocity and very low pressure-near absolute zero and lower
than the vapor pressure of the power fluid itself. This ultra low
fluid pressure at the nozzle exit 3 causes the power fluid to
vaporize and the creation of cavitation vapor bubbles. Third,
solids-ladened well fluids (arrows WF) enter the wellbore under
formation pressure at well fluids inlet 7. As the well fluids and
solids enter the power fluid stream, the power fluid velocity
decreases and the static pressure increases, thereby causing the
cavitation vapor bubbles to recollapse as the power fluid is
recaptured by the throat 100. The cavitation vapor bubble
formation-and-recollapse action is extremely violent and causes
severe mixing of the power fluid (arrows PF) and the wellbore
fluids (arrows WF) being drawn in. As depicted schematically in
FIG. 4, the severe mixing action forces the solids to be fully
immersed in the combined return fluid stream (arrow R). This full
immersion of the solids causes the solids to enter the center of
the throat passage, thereby lessening the solids' direct contact
with the internal walls of the throat entrance at high impact area
2. As a result, erosion of the throat 100 is reduced. Operating the
jet pump using the cavitation method of the present invention is
thus an improvement over prior art methods having no or inferior
erosion resistance.
[0032] Operating a jet pump in cavitation mode provides a maximum
limit on the wellbore flow rate. Maximum wellbore flow rate is a
function of multiple parameters, including nozzle diameter, throat
diameter, and wellbore pressure, as well as pump pressure and pump
rate. After achieving the maximum wellbore flow rate, an additional
increase in the pump rate achieves no incremental increase in
returns at the surface. Therefore, whether a jet pump is operating
in cavitation mode downhole may be determined at the surface by the
presence of further increases in pump pressure and pump rate
without achieving more suction or an increase in returns.
[0033] For example, initially the jet pump may operate at a pump
rate of 60 liters per minute (lpm), with fluid returning to the
surface at the same rate of 60 lpm. As the pump rate is increased,
e.g. to 61 lpm, the fluid return rate may increase as more wellbore
fluid is drawn into the return fluid stream, e.g. to 62 lpm. If the
pump rate is increased further, e.g. to 70 lpm, the fluid return
rate may increase further, e.g. to 90 lpm. The difference between
the fluid return rate (out of system) of 90 lpm and the pump rate
(into system) of 70 lpm is 20 lpm, which indicates that the system
yields an additional 20 lpm in suction. Now, if the pump rate is
increased further to 80 lpm, and the fluid return rate is 100 lpm,
the net system increase would remain at 20 lpm in suction. Because
further increases in pump rate do not achieve an increase in
suction or fluid returns, the system is operating at its maximum,
and it may be deduced from the surface that the jet pump is
operating in cavitation mode downhole.
[0034] Experimental results have been obtained for this embodiment
of the present invention. A test was set up wherein a jet pump was
operated in cavitation mode to draw a sand/water slurry from a
simulated wellbore. The erosion rate of the throat, which is
proportional to the cross-sectional area of throat removed per
volume of sand removed from the well, was approximately 50% of
normal wear when the jet pump is not operated in cavitation mode.
Representative experimental data are provided in TABLE 1 below.
1TABLE 1 Experimental Data Test # 044 Test # 034 Test # 044
(continued) Measured Parameter Jul. 10, 2003 Oct. 9, 2003 Oct. 15,
2003 Setup Nozzle diameter (in) 0.070 0.070 0.070 Throat diameter
(in) 0.102 0.102 0.102 Flow Rates Nozzle flow rate (LPM) 44 51 51
Diffuser flow rate (LPM) 50 67 67 Wellbore flow rate (LPM) 6 16
(max) 16 (max) Pressures Nozzle pressure (psi) 7600 9500 9500
Diffuser pressure* (psi) 4500 4500 4500 Wellbore pressure (psi)
1000 1000 1000 Suction pressure (estimated 900 0 (cavitation) 0
(cavitation) psi) Sand Removal Results Volume of sand removed 6200
5750 13000 "SR" (in.sup.3) Worn throat diameter (in) 0.113 0.107
0.115 Cross sectional area of 0.00186 0.00082 0.00222 throat
removed "Area" (in.sup.2) Ratio SR/Area .times. 1000 (in) 3330 7000
5860 Comments Low suction Pump at Realize flow rate cavitation to
cavitation maximize erosion benefit sand intake *Diffuser pressure
of 4500 psi is required for operations at 9,000 feet total vertical
depth (TVD).
[0035] Sand was removed from a simulated well of 9,000-foot total
vertical depth in conventional and cavitation modes of operation.
Simulated well conditions included a jet pump assembly with a
nozzle of 0.070-inch diameter, a throat of 0.102-inch diameter, and
a throat configuration having a 5-micron thick layer of
polycrystalline diamond (PCD).
[0036] The erosion of the throat 100 using the cavitation jet pump
operational mode of the present invention was compared to the
erosion of the throat 100 using the conventional jet pump
operational mode. Operating the jet pump in cavitation mode allowed
sand removal for a longer period than conventionally. The
experimental data suggests a 50% to 150% improvement in downhole
component longevity due to a 50% to 150% improvement in erosion
performance. These improvements suggest a corresponding increase in
operational efficiency by way of a reduced need for frequent trips
in and out of hole.
[0037] Although various embodiments have been shown and described,
the invention is not so limited and will be understood to include
all such modifications and variations as would be apparent to one
skilled in the art. Specifically, the erosion-decreasing method
disclosed herein may be beneficially employed by pumping the power
fluid through the jet pump at a sufficient velocity to cause the
power fluid pressure in the area between the nozzle and throat
and/or in the throat itself to be less than or equal to the power
fluid vapor pressure. Similarly, cavitation vapor bubbles in the
power fluid may be created in the area between the nozzle and
throat and/or in the throat itself. In addition, the wellbore fluid
and power fluid may be mixed while the fluid pressure is less than
or equal to the power fluid vapor pressure or shortly before the
fluid pressure drops to the power fluid vapor pressure or
immediately after the cavitation bubbles of the power fluid are
recaptured.
* * * * *