U.S. patent application number 13/726589 was filed with the patent office on 2013-05-09 for system and method for direct drive pump.
This patent application is currently assigned to HARRIER TECHNOLOGIES, INC.. The applicant listed for this patent is Harrier Technologies, Inc.. Invention is credited to William Bruce Morrow, Raymond Witten.
Application Number | 20130112431 13/726589 |
Document ID | / |
Family ID | 43623135 |
Filed Date | 2013-05-09 |
United States Patent
Application |
20130112431 |
Kind Code |
A1 |
Morrow; William Bruce ; et
al. |
May 9, 2013 |
SYSTEM AND METHOD FOR DIRECT DRIVE PUMP
Abstract
A method and a system are provided for a direct drive pump for
use in pumping fluids and/or quasi-fluids from one location to
another. In the direct drive pump, bearings or bushings are
optimally spaced, taking into account various operational
considerations such as load, path, pressure, and tension. Further,
bearings or bushings are coupled to the drive string, thus
assisting in more efficient installation and de-installation. The
bearings or bushings are not fixed to the production casing or
drive tube. In embodiments, the drive tube can be vented, and the
production fluid can be used as a lubricant for the system
bearings.
Inventors: |
Morrow; William Bruce;
(Santa Barbara, CA) ; Witten; Raymond; (Owasso,
OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Harrier Technologies, Inc.; |
Greenwich |
CT |
US |
|
|
Assignee: |
HARRIER TECHNOLOGIES, INC.
GREENWICH
CT
|
Family ID: |
43623135 |
Appl. No.: |
13/726589 |
Filed: |
December 25, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12552806 |
Sep 2, 2009 |
8336632 |
|
|
13726589 |
|
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Current U.S.
Class: |
166/380 ;
166/105; 166/66.4 |
Current CPC
Class: |
F04D 13/10 20130101;
E21B 43/126 20130101; F04D 29/046 20130101; E21B 19/16
20130101 |
Class at
Publication: |
166/380 ;
166/105; 166/66.4 |
International
Class: |
E21B 43/12 20060101
E21B043/12; E21B 19/16 20060101 E21B019/16 |
Claims
1. A direct drive pump system, comprising: a well casing, the well
casing being a housing for the direct drive pump system; a pump
having a pump inlet situated at a lower end of the well casing; a
production tubing; a drive string rod, the drive string rod being
situated within the production tubing; at least one of a stabilizer
and a bearing, the at least one of a stabilizer and a bearing being
disposed on the drive string rod and serving as support for the
drive string rod to ensure stable rotation during operation of the
pump; wherein the pump situated downhole in the well casing drives
the drive string rod to rotate to encourage well fluid pressurized
from the pump to flow uphole towards the surface for
production.
2. The pump system of claim 1, wherein the at least one of a
stabilizer and a bearing is closely spaced along the entire length
of the drive string rod to ensure stable rotation during operation
of the drive string rod.
3. The pump system of claim 2, wherein the at least one of a
stabilizer and a bearing is at least one of a bearing assembly, a
bushing, a bearing mounted in a housing, a bearing mounted in a
plastic housing, a ceramic-polymer alloy bearing, a ceramic
bushing, a non-corrosive bearing, and a ceramic bearing.
4. The pump system of claim 2, wherein the fluid flow passes around
an outer surface of the production tubing.
5. The pump system of claim 2, comprising: a drive tube, the drive
tube being situated within the production tubing; and at least one
centralizer, wherein the at least one centralizer is associated
with the drive tube and supports the drive tube so that the drive
tube remains fairly centered in the production tubing, and the
drive string rod and its stabilizers are situated within the drive
tube.
6. The pump system of claim 2, wherein the fluid flow passes around
an outer surface of the drive tube.
7. The pump system of claim 1, further comprising a pressure
regulator situated between a well pump and a production flow line,
wherein the pressure regulator opens when the pressure differential
between the drive tube and the production tubing exceeds a
predetermined set value.
8. The pump of claim 1, further comprising a motor to drive the
pump in order to drive the drive string rod, wherein the motor is
an electric motor which effectively drives the rod string at one
of: a low RPM with speed increasing capability gearing, and about
3500 RPM pump operational speed.
9. The pump of claim 1, wherein the pump provides a high volume
artificial lift system of well fluid.
10. A method for installing a direct drive pump in a well,
comprising: coupling a bottom hole assembly to a first length of
production tubing; lowering the bottom hole assembly and the first
length of production tubing into a well; securing the production
tubing in a wellhead; coupling an additional length of production
tubing to the first length of production tubing; lowering the
additional length of production tubing into the well; lowering a
first length of drive tube down inside the production tubing
lengths; securing the first length of drive tube to the wellhead;
coupling an additional length of drive tube to the first length of
drive tube; lowering the additional length of drive tube inside the
production tubing lengths; lowering a first length of at least one
drive rod down inside the drive tube, the at least one drive rod
having at least one stabilizer for supporting the drive rod in the
respective length of drive tube; coupling an additional length of
at least one drive rod to the first length of at least one drive
rod; lowering the additional length of at least one drive rod down
inside the drive tube; and attaching a drive head to the production
tubing, drive tube, and drive rods such that the lengths of drive
rods can be turned by a motor to drive the pump in the bottom hole
assembly.
11. The method of claim 10, wherein more lengths of production
tubing are attached in succession to the additional length of
production tubing until a desired depth by the bottom hole assembly
is reached in the well and the lengths of production tubing are
secured to the wellhead, more lengths of drive tube are attached in
succession to the additional length of drive tube until a desired
depth is reached in the well and the lengths of the drive tube are
secured to the wellhead, and more lengths of at least one drive rod
are attached in succession to the additional length of at least one
drive rod until a desired depth is reached in the well, and the
lengths of the at least one drive rod are supported by stabilizers
in the drive tube.
12. The method of claim 11, wherein the bottom hole assembly
includes a multi-stage pump, a thrust bearing, a drive rod, and a
drive tube receiver.
13. The method of claim 12, wherein at least one of at least two
lengths of the drive tube, at least two lengths of production
tubing, and at least two lengths of drive rods are mated by a
threaded connection.
14. The method of claim 13, wherein each respective length is two
30 feet segments, the two segments being coupled together and
lowered into the well as a single length.
15. The method of claim 14, wherein the length of drive rod string
includes a splined rod connector on one end and a stab-in receiver
on the other end, so that when the splined rod connector of the
first length of drive rod string meets the stab-in receiver of the
additional length of drive rod string.
16. The method of claim 15, wherein a surface flow line is attached
to the wellhead.
17. A method for installing a direct drive pump in a well,
comprising: coupling a bottom hole assembly to a first length of
production tubing; lowering the bottom hole assembly and the first
length of production tubing into a well; securing the production
tubing in a wellhead; coupling an additional length of production
tubing to the first length of production tubing; lowering the
additional length of production tubing into the well; lowering a
first length of at least one drive rod down inside the production
tubing, the at least one drive rod having at least one stabilizer
for supporting the drive rod in the respective length of production
tubing; coupling an additional length of at least one drive rod to
the first length of at least one drive rod; lowering the additional
length of at least one drive rod down inside the production tubing;
and attaching a drive head to the production tubing and drive rods
such that the lengths of drive rods can be turned by a motor to
drive the pump in the bottom hole assembly.
Description
FIELD OF INVENTION
[0001] The present invention relates to a system and method for a
direct drive pump to be used for moving liquids and/or
quasi-liquids. The present invention also relates to a system and
method for the installation of a direct drive pump, for example,
for high volume lifts from deep wells.
BACKGROUND
[0002] Current systems for deep well pumping involve electrical
submersible pumps ("ESPs") or geared centrifugal pumps ("GSPs").
Such pumps are the current, principal methods used as artificial
lifts in high rate oil wells, where a multi-stage centrifugal pump
is located downhole. For example, in an ESP system, a downhole
electrical motor directly drives the pump, with electric power
supplied to the motor via a cable extending from the surface to the
motor's location downhole. For example, in a GSP system, the pump
is driven via a rotating rod string extending from the surface to a
speed increasing transmission system located downhole. The speed
increasing transmission system is used to increase the relatively
slow rotation of the rod string to a much faster rotation, as
needed by the pump. In this example, the rod string is driven by a
prime mover at the surface.
[0003] In current systems, the artificial lift system tends to be a
bit burdensome. For example, in the installation of a current
artificial lift system, a 300 to 400 foot artificial pump is
installed in 10 foot sections in assembly form. Likewise, in the
maintenance of a specific section of the pipe or tubing, the entire
section of the pump must be removed all at once before any
maintenance can be made.
[0004] FIGS. 1A and 1B show example line shaft pumps. FIG. 1A shows
a line shaft pump with water lubricated bearings. In FIG. 1A, the
drive shaft is running directly inside the production tubing, or
column pipe. Unlike the example shown in FIG. 1B, this pump does
not use an oil pipe. Instead, in FIG. 1A, the drive shaft is
centered within the column pipe by water lubricated bearings and
bearing retainers attached to the column pipe. Such bearings are
typically made of rubber, due to use in water. The pump thrust, as
well as the weight of the drive shaft itself, are carried by a
thrust bearing located at the surface.
[0005] FIG. 1B shows a line shaft pump with an oil pipe and oil
lubricated bearings. In FIG. 1B, an oil lubricated drive shaft
rotates inside the oil pipe, or oil filled tubular housing. The
drive shaft is supported by shaft bearings, e.g., bronze bushings,
attached fixedly to the oil pipe. The bushings are spaced, e.g., 5
feet to 10 feet, on yhr oil pipe and along the drive shaft
depending upon the intended rotational speed of the drive shaft. In
this example, the steel pump shaft forms the journals for the
bronze bushings. The pump thrust, as well as the weight of the
drive shaft itself, are carried by a thrust bearing at the surface.
Accordingly, the oil pipe can be centered within the column pipe by
elastomer centralizers spaced evenly along its length as shown in
FIG. 1B.
[0006] In both FIGS. 1A and 1B, there is a required bearing spacing
for adequate support of the drive shaft. Such spacing affects the
configuration of the tubulars used in installation. For example, in
a water lubricated system shown in FIG. 1A, if the drive shaft
bearings are required every 10 feet, then the column pipe is used
in 10 foot segments. The bearing retainers are fixed to the column
pipe at the column pipe couplings. For example, in an oil
lubricated system shown in FIG. 1B, if the drive shaft bearings are
required every 10 feet, then the oil pipe is used in 10 foot
segments. The bushings are fixed to the drive shaft housing at the
housing couplings. In both examples, the pump systems can be
installed in similar fashion. For example, if the bearing spacing
is deemed to be 10 feet, then all of the components including the
column pipe, oil pipe, and drive shaft, are in 10 foot length
segments. Thus, as the pump is lowered into a well, each of the 10
foot segments of the drive shaft, bearings and column or oil pipe,
must be installed in 10 foot segments.
[0007] Accordingly, a need exists for a less burdensome
installation, de-installation, and maintenance of a pump system for
both oil and water lubrication systems.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1A shows a line shaft pump having water lubricated
bearings.
[0009] FIG. 1B shows a line shaft pump with oil lubricated
bearings.
[0010] FIG. 2 shows an exemplary embodiment of a direct drive pump
according to an embodiment of the present invention.
[0011] FIG. 3 shows an exemplary embodiment of a drive rod with a
drive tube according to an embodiment of the present invention.
[0012] FIG. 4 shows an exemplary embodiment of a drive rod without
a drive tube according to an embodiment of the present
invention.
[0013] FIG. 5A shows a cross-sectional view of a stabilizer
embodiment for the direct drive pump according to an embodiment of
the present invention.
[0014] FIG. 5B shows a top view of a stabilizer embodiment for the
direct drive pump according to the embodiment of the present
invention shown in FIG. 5A.
[0015] FIG. 5C shows a front view of a stabilizer embodiment for
the direct drive pump according to the embodiment of the present
invention shown in FIG. 5A.
[0016] FIG. 6A shows a cross-sectional view of a stabilizer
embodiment for the direct drive pump according to an embodiment of
the present invention.
[0017] FIG. 6B shows a top view of a stabilizer embodiment for the
direct drive pump according to the embodiment of the present
invention shown in FIG. 6A.
[0018] FIG. 6C shows a front view of a stabilizer embodiment for
the direct drive pump according to the embodiment of the present
invention shown in FIG. 6A.
[0019] FIG. 7A shows a cross-sectional view of a stabilizer
embodiment for the direct drive pump according to an embodiment of
the present invention.
[0020] FIG. 7B shows a top view of a stabilizer embodiment for the
direct drive pump according to the embodiment of the present
invention shown in FIG. 7A.
[0021] FIG. 7C shows a front view of a stabilizer embodiment for
the direct drive pump according to the embodiment of the present
invention shown in FIG. 7A.
[0022] FIG. 8A shows a cross-sectional view of a stabilizer
embodiment for the direct drive pump according to an embodiment of
the present invention.
[0023] FIG. 8B shows a top view of a stabilizer embodiment for the
direct drive pump according to the embodiment of the present
invention shown in FIG. 8A.
[0024] FIG. 8C shows a front view of a stabilizer embodiment for
the direct drive pump according to the embodiment of the present
invention shown in FIG. 8A.
[0025] FIG. 9A shows a cross-sectional view of a stabilizer
embodiment for the direct drive pump according to an embodiment of
the present invention.
[0026] FIG. 9B shows a top view of a stabilizer embodiment for the
direct drive pump according to the embodiment of the present
invention shown in FIG. 9A.
[0027] FIG. 9C shows a front view of a stabilizer embodiment for
the direct drive pump according to the embodiment of the present
invention shown in FIG. 9A.
[0028] FIG. 10 shows an embodiment of a direct drive pump bottom
hole assembly with a drive tube according to the present
invention.
[0029] FIG. 11 shows an embodiment of a direct drive pump bottom
hole assembly without a drive tube according to the present
invention.
[0030] FIG. 12 shows an embodiment of a top vented drive tube
according to the present invention.
[0031] FIG. 13 shows an embodiment method for installing a direct
drive pump according to the present invention.
DETAILED DESCRIPTION
[0032] Embodiments of the present invention provide for a
relatively easy to install and maintain artificial lift pump for
use in oil and water pump systems. More specifically, embodiments
of the present invention may be used for deep well pumping of oil,
water, or other fluid/quasi-fluid.
[0033] Embodiments of the present invention provide for a deep well
pump system which can be utilized at a greater depth and/or with a
greater rotational speed than current pump systems allow. For
example, water wells tend to be relatively large in diameter, e.g.,
10 inches to more than 16 inches. Accordingly, available
agricultural centrifugal pumps used in water wells require large
diameter pump rotor which produce a large increase in pressure per
stage. That is, pressure per stage is proportional to the square of
the rotor diameter, and the square of the rotational speed. Given
the large diameter and typically shallow depth of a water well,
water well turbine pumps typically are operated at speeds between
about 1200 RPM and 1800 RPM. Comparatively, oil wells tend to use
an about 5.5 inch or 7 inch production casing having an inside
diameter of about 4.6 inches to 6 inches. Accordingly, available
centrifugal pumps require a small diameter pump rotor, providing a
small pressure increase per stage. This small pressure increase per
stage results in the pump having to be operated at a high speed,
e.g., about 3500 RPM. Even at such high speed, due to the small
pressure increase per stage and the typically deep depth of oil
wells, there can be as many as 250 or more stages required to bring
the produced fluid to the surface or other desired location. If
such pumps for oil production were operated at the typical speed of
an agricultural pump (e.g., for a water well), about 1000 stages or
more could be required to bring the produced fluid to the surface
or other desired location, which would be prohibitively expensive
and wearing on the system. In embodiments of the present invention,
such restrictions and expense of the agricultural and oil pump
systems are alleviated or diminished.
[0034] Embodiments of the present invention provide for a pump
installation in which larger sections of the pump may be installed
than current pump systems allow. For example, in agricultural and
oil pumps, the drive shaft is stabilized by bearings that are fixed
to either the tubular drive shaft housing, i.e., the oil pipe, or
the column pipe. Each of these segments are made to be all the same
length so that the bearings can be fixed to the column pipe or oil
pipe at the junction of the segments of pipe as the pump is being
installed into the well. In an oil lubricated bearing system,
bronze bushings are attached to the oil pipes, with a steel drive
shaft forming the journal. In a water lubricated bearing system,
the rubber bearing is held in the center of the column pipe by the
bearing retainers. The drive shaft runs through the rubber bearing
and is fitted with a stainless steel sleeve serving as journal. In
both the agricultural (e.g., water) and oil pump systems, the
bearing is affixed to the column pipe or oil pipe, respectively.
Accordingly, as discussed above, the installation of such available
systems require assembly of each 10 feet of pump system segments.
Embodiments of the present invention provide for installations of
larger pump system segments, e.g., 25 foot sections, 60 foot
sections, and more.
[0035] Embodiments of the present invention provide for a high
volume artificial lift system, i.e., a direct drive pump ("DDP"),
in which a multi-stage downhole centrifugal pump is driven by a rod
string extending from the surface to the downhole pump. The rod
string is driven at the surface, e.g., ground level, by a prime
mover, e.g., an electric motor. For example, the motor may drive
the rod string at a 3500 RPM pump operational speed. This speed can
be decreased or increased, depending upon the situation needed, in
embodiments of the present invention.
[0036] Embodiments of the present invention provide for closely
spaced bearings to provide rotational stability of the drive
string. In an embodiment, the individual bearings are attached to
the drive string, and are not fixed to the production casing or
drive tube.
[0037] FIG. 2 shows an embodiment of a direct drive pumping system
220 according to the present invention. In FIG. 2, a motor 200 is
shown connected to the remaining elements of the pump via tubing
hangers and at least one thrust bearing 201. In an embodiment, the
motor 200 is an electric motor which drives the rod string at full
pump speed. Alternatively, the motor 200 is a direct drive motor,
e.g., turning at 3500 RPM. Alternatively, the motor 200 has a low
output RPM, i.e., lower than 3500 RPM, but with speed increasing
capability gearing. In this embodiment, the pressure of the pump
system is monitored by a pressure regulator 202 situated between
the pump and the flow line 203 to the pump. The pressure regulator
202 opens when the pressure differential between the drive tube and
the production tubing exceeds a predetermined, set value. A
wellhead 204 couples the well casing to the upper portion of the
pump system which includes the motor 200 and the flow line pipe
203. Inside the protective well casing 205, a production tubing or
pipe 207 is situated and houses a drive rod string 206. The lower
portion of the pump system includes a receiver and thrust
bearing(s) 208. In an embodiment, the thrust bearing 208 carrying
the weight of the drive rods is located in the surface drive head.
Due to the high rotational speed, the rod string 206 is equipped
with stabilizers or bearings closely spaced along the entire length
of the rod string to assure stable rotation. Some example
embodiments of such stabilizers are shown herein. Perforations 209
in the well casing in the pay zone 212 area, i.e., where the water
or oil or other liquid/quasi-liquid is located, allow for entry of
the liquid or quasi-liquid into the well casing for pumping via the
pump 210 having a pump inlet 211, up to the surface or other
desired location.
[0038] FIG. 3 shows an embodiment of a drive rod 304 having a drive
tube 301 according to an embodiment of the present invention. For
example, in larger sizes of production tubing, the drive rod string
304 and stabilizers 305 rotate within a small diameter tubular
housing called a drive tube 301. The drive tube 301 runs inside the
production tubing 302. In order to stabilize the drive tube 301,
drive tube stabilizers 303 are spaced between the production tubing
302 and the drive tube 301. Within the drive tube 301 itself, the
drive rod string 304 is supported by drive rod stabilizers 305 to
the drive tube 301.
[0039] FIG. 4 shows an embodiment of a drive rod string 402 being
encased directly in production tubing 401. In such case, the drive
rod string 402 is supported by drive rod stabilizers 403 to the
production tubing 401. Such an embodiment may be used in the
situation of a relatively small diameter production tubing, where
there is insufficient and/or no need for a drive tube.
[0040] FIGS. 5, 6, and 7, show embodiments of bearing assemblies or
stabilizers for a direct drive pump embodiment which does not
utilize a drive tube according to the present invention. In each of
these embodiments, the bearing assembly includes a bushing attached
to a rod body, with a bearing mounted in a housing, e.g., a plastic
or other type housing, that closely fits the internal diameter of
the production tubing. The housing, and thus, the bearing, remain
fixed relative to the tubing with the rod string rotating within
the bearing. FIG. 5 shows a ceramic-polymer alloy bearing example
embodiment. In FIG. 5A, a polymer housing and bearing 500 are
situated near a ceramic bushing 501, the ceramic bushing 501 being
situated on the drive rod 502. In FIG. 5B, the polymer housing and
bearing 500 surrounding the ceramic bushing 501 are shown. A
resulting flow area is available outside of the polymer housing
500. In FIG. 5C, a front view of the assembly is shown in which
inside the production tubing 503, a retention band 504 is used to
hold the housing 500 which surrounds a portion of the drive rod
502.
[0041] FIG. 6 shows a non-corrosive bearing example embodiment. In
FIG. 6A, a polymer housing and bearing 600 are situated near a
molded stop 601, e.g., a molded plastic stop, the molded stop 601
being situated on the drive rod 602. In FIG. 6B, the polymer
housing and bearing 600 surrounding the drive rod 602 are shown. A
resulting flow area is available outside of the polymer housing
600. In FIG. 6C, a front view of the assembly is shown in which
inside the production tubing 603, a retention band 604 is used to
hold the housing 600 which surrounds a portion of the drive rod
602.
[0042] FIG. 7 shows a ceramic bearing example embodiment. In FIG.
7A, a plastic housing and bearing 700 are situated near a ceramic
bushing 701, the ceramic bushing 701 being situated on the drive
rod 702. In FIG. 7B, the plastic housing and bearing 700
surrounding the ceramic bushing 701 are shown. A resulting flow
area is available outside of the plastic housing 700. In FIG. 7C, a
front view of the assembly is shown in which inside the production
tubing 703, a retention band 704 is used to hold the housing 700
which surrounds a portion of the drive rod 702.
[0043] In embodiments of the present invention, the bearing
material to be used depends upon the wear and lateral load expected
at the bearing's location within the well. For example, where high
lateral loading is expected due to bore hole deviations, ceramic or
even carbide bearings can be used. Or, for example, where not much
side loading is expected, simpler and less expensive polymer alloy
bearings can be used. The bearing housing material can be plastic,
nylon, polymer alloy, or some other strong, chemically inert
material.
[0044] In embodiments of the present invention, various types of
bearings can be used. Determining which bearing type to use can
depend upon the expected load, depth of the pump, use of a drive
tube, and other considerations. In FIGS. 5 to 9, the bearings
differ in the provision for fluid flow around the bearing housing.
For example, when a drive tube is not used, the bearings are
exposed to the production fluid flow, thus the area open to flow
between the bearing housing and the inside of the production tubing
should be maximized to reduce pressure losses as the fluid flows
past the bearings. See, e.g., FIGS. 5 to 7. Or, for example, when a
drive tube is used, the fluid in the tube is virtually stagnant,
and the bearing housings need only be fluted enough to allow for a
low rate flow communication throughout the drive string. See, e.g.,
FIGS. 8 and 9.
[0045] FIGS. 8 and 9 show embodiments of bearing assemblies or
stabilizers for a direct drive pump embodiment having a drive tube
according to the present invention. In each of these embodiments,
the bearing assembly includes a bushing attached to a rod body,
with a bearing mounted in a housing, e.g., a plastic or other type
housing, that closely fits the internal diameter of the drive tube
housing. The housing, and thus, the bearing, are situated to remain
fixed relative to the drive tube housing with the rod string
rotating within the bearing.
[0046] FIG. 8 shows a ceramic-polymer alloy bearing example
embodiment. In FIG. 8A, a polymer housing and bearing 800 are
situated near a ceramic bushing 801, the ceramic bushing 801 being
situated on the drive rod 802. A drive tube 805 surrounds this
assembly. In FIG. 8B, the production tubing 803 surrounds the drive
tube 805 which surrounds the bearing assembly. In FIG. 8C, a front
view of the assembly is shown in which within the drive tube 805, a
retention band 804 is used to hold the housing 800 which surrounds
a portion of the drive rod 802.
[0047] FIG. 9 shows a ceramic bearing example embodiment. In FIG.
9A, a plastic housing and bearing 900 are situated near a ceramic
bushing 901, the ceramic bushing or bearing 901 being situated on
the drive rod 902. A drive tube 905 surrounds this bearing
assembly. In FIG. 9B, the production tubing 903 is shown
surrounding the drive tube 905 which surrounds the bearing
assembly. In FIG. 9C, a front view of the assembly is shown in
which inside the drive tube 905, a retention band 904 is used to
hold the housing 900 which surrounds a portion of the drive rod
902.
[0048] In embodiments of the present invention, the bearing
assembly, or configuration, provides that the tubulars and the
drive string can be run separately and sequentially, rather than
simultaneously as done in currently available pump systems. In
embodiments of the present invention, the bearing assembly allows
for individual segments of pipe and drive string to be much longer
since the bearings are not attached to the tubulars' couplings.
Thus, the couplings can be spaced much more widely, without having
to adjust for the earlier necessary placement of bearings.
Accordingly, this allows for relatively easier service and
maintenance of the pump system. For example, when the pump requires
service, the drive rods and/or tubulars can be pulled from and
subsequently rerun into the well in large lengths, e.g. several
feet, 100 foot lengths, etc., at a time. Further, in an embodiment,
the tubing couplings are threaded, instead of having flange
couplings, e.g., as shown in FIGS. 1A and 1B, thus greatly
improving seal integrity and speed of installation.
[0049] In an embodiment of the present invention, mounting such
bearing assemblies on a drive rod allows the bearings to be located
optimally as required by the conditions in the well. For example,
such conditions may include rod tension and potential side loads in
the well due to, e.g., borehole deviation. In an example, the
rotational stability of a drive string is a function of rod
tension. That is, the higher the tension, the more stably the rod
will rotate. However, at the bottom of the hole, near the pump, the
rod may have little tension. Thus, at this location of the pump in
the well, the bearing spacing needs to be the closer in space in
order to assure stable rotation. Likewise, proceeding up the hole
toward the surface, the tension of the rod increases as the weight
of the rod hanging below effectively is increased. Thus, the
spacing of the bearings can be increased in this area. That is,
where the rod tension is greatest, the relative bearing spacing
along the drive rod may be the widest and still be adequately
effective. In an embodiment of the present invention, an optimized
drive rod string has bearings spaced according to the requirements
dictated by the rod tension.
[0050] In a practical situation, wells--oil or water--are
frequently neither perfectly straight nor vertical. Thus, a drive
rod rotating within tubing with a small diameter may be forced to
the side by deviations of the direction of the well, causing
lateral loads on the bearings situated in and/or near the area of
the deviation. The drive rod bearings are principally designed to
keep the rod string rotating stably, and are normally expected to
exposed to only small lateral loads. However, if side loads are
expected to be unusually high due to borehole deviations, special
bearings designed for side-load resistance can be installed in
those areas where high lateral load is expected, e.g., the ceramic
bearings as shown in FIGS. 5 to 9.
[0051] In embodiments of the present invention, relatively easy
maintenance is needed due to the structure of the pump system. In
an embodiment, the drive rod(s) can be removed without having to
remove the other components. Such allows for relatively easy
"tuning" or adjustment of the pump system for changing/changed
operational conditions, or for normal maintenance. For example, if
an operation condition such as pump speed is changed, the drive
rod(s) can be replaced with other drive rod(s) having a more useful
bearing type, configuration, and/or distribution. For example, if
the pump speed is increased in order to increase liquid production,
the drive rods can be easily replaced with one with a different
distribution of bearings that is designed for the higher rotational
speed. Likewise, if there is a failure in one or more of the drive
rods, a replacement drive rod(s) can be quickly run downhole thus
minimizing downtime.
[0052] Embodiments of the present invention provide for pumping at
greater depths. Presently available line shaft pump systems
typically have a head capacity of less than 1500 feet, and are run
to depths of less than 1000 feet. The relatively short length of
the pipes and drive shaft results in a small amount of stretch by
the components due to, e.g., water column weight and/or pump
thrust, during operation. Such stretch allows the supporting thrust
bearing for the drive shaft to be located at the surface. See,
e.g., FIGS. 1A and 1B, described above. This allows for small
manual adjustments to the relative length of those components so
that the pump impellers--which are fixedly attached both
torsionally and axially to the drive shaft--turn freely. In
embodiments of the present invention, however, given the greater
depth of the components allowed, and consequently the greater
hydrostatic forces, there is a much greater relative movement
between the production tubing to which the pump is attached and the
drive rods and/or drive tube, allowing for a more flexible range of
manual adjustment.
[0053] In FIG. 10, an embodiment of the direct drive pump hole
assembly having a drive tube according to the present invention is
shown. In such an embodiment, the pump drive shaft thrust bearing
can be placed immediately above or below the pump. The pump drive
shaft and rotors are driven by the drive rod(s) 1000 via a spline
coupling or spline rod connector 1005 that allows for significant
relative vertical movement of production tubing and the drive
rod(s) 1000 while allowing the pump drive shaft and rotors to
remain axially fixed relative to the pump body. In an embodiment,
there is an additional thrust bearing located at the surface to
handle the weight of the drive string. See, e.g., FIG. 2. In FIG.
10, the production tubing 1003 surrounds the drive tube 1001 which
surrounds the drive rod 1000. Stabilizers 1002 are located on and
spaced to support the drive rod 1000. Within the drive tube 1001
itself, is a bottom drive tube vent 1004. FIG. 10 further shows the
relationship and relative locations of a seal bore drive tube
connection 1006, stab-in receiver 1007, stab-in receiver vent 1008,
thrust bearing 1009, pump 1010, and pump intake 1011.
[0054] FIG. 11 shows an embodiment of the present invention similar
to that shown in FIG. 10, except without a drive tube 1001. In this
embodiment, a spline coupling 1105 is still employed. Further, use
of a thrust bearing 1101, e.g., a polycrystalline diamond (PCD)
thrust bearing, is shown situated below the pump and above the pump
intake.
[0055] FIG. 12 shows an embodiment of the present invention having
a top vented drive tube. FIG. 12 shows an enlarged section of the
pump system just below the wellhead 1201. A well casing 1208
surrounds the production tubing 1200, the production tubing 1200
surrounding the drive tube 1203. The drive tube 1203 is shown
having vents 1202 in its upper area to allow for fluid flow. As the
drive rod 1204 located within the drive tube 1203 moves in
operation, the drive rod stabilizers 1205 are located on and
support the rod. In operation of the embodiment, fluid flow in the
production tubing 1200, within the drive tube 1203, and from the
drive tube 1203 moves upward toward the surface.
[0056] In embodiments of the present invention, various lubricants
can be used for the bearings. For example, in an embodiment having
a large production housing or tubing, a drive tube having a smaller
diameter can be utilized to encase the drive rod. The drive tube
may be centralized within the production tubing, and be used to
essentially protect the drive rod from corrosion and scale
deposition that might occur in the flow stream of a produced fluid.
In such an embodiment, lubrication of the bearings must be chosen
so as to not negatively affect other parts of the system, e.g.,
sealing between components, etc. For example, in some systems, oil
is used as a lubricant. In such systems, an oil lubricant can be
useful at relatively shallow depths. However, using an oil
lubricant at relatively greater depths can cause sealing issues
between the produced fluid in the production tubing and the oil in
the drive tube. Such issues can occur because of the difference in
the density of the lubricating oil and the produced well fluid,
e.g., typically water. For example, at deep depths, e.g., 6000
feet, the pressure difference between a column of lubricating oil
with a specific gravity of 0.9, and water, with a specific gravity
of 1.0, is nearly 260 psi at 6000 foot depth. And, in a pumping
system, if the produced fluid and the lubricating oil are to be
kept separate, the seals at the bottom of the oil filled drive tube
must seal against this 260 psi pressure differential at 3500 RPM.
This pressure situation can presents potential operational
difficulties. In the alternative, one can pressure up the oil
column at the surface to 260 psi so that the bottom hole pressures
of the oil column and the produced fluid column are equal, or
nearly so, relieving the pressure differential across the seals.
This alternative also present operational difficulties. For
example, if there are any changes in surface producing pressures,
and during well shut-downs and start-ups, the surface pressure in
the drive tube will need to be adjusted to the expected changes in
bottom hole producing pressure. In another alternative, an oil
lubricant having a similar density to that of water can be used so
that the hydrostatic pressure in both columns is about equal at the
bottom of the hole. This too presents difficulties in that such
oils are synthetic, and thus, cost prohibitive. In embodiments of
the present invention, these difficulties are overcome. For
example, a water lubricated drive shaft in an embodiment of the
present invention provides the benefits of the oil lubricated
system without the operation difficulties, lubricant costs, and/or
pressure balancing issues. The water lubricated system involves the
drive shaft turning within a small diameter drive tube, and
equipped with closely spaced bearings to provide rotational
stability, as discussed herein. In an embodiment, the drive tube is
not sealed off from the produced fluid. The produced fluid fills
the drive tube and serves as the bearing lubricant. In such an
embodiment using water as a lubricant, bearings designed for water
lubrication can be used. Such bearings can designed using ceramic,
carbide, or polymer alloy bearings, depending upon the load and
wear requirements, as discussed herein. As shown in FIG. 12, the
drive tube is vented to the production flow line at the surface to
expel oil or gas that collects in the tub, and to allow the rate of
flow up the drive tube to be controlled. In an embodiment, the
drive tube is vented into the production tubing below the wellhead,
allowing produced fluid to flow continuously up the drive tube.
This can improve lubrication and/or improve the cooling of the
bearings. In an embodiment, using a produced fluid filled drive
tube can provide both cost and reliability benefits. In this
embodiment, the drive shaft seals at the pump assembly are not
needed. Instead, a bushing, e.g., carbide, is used to center the
shaft at the bottom of the drive tube. The drive tube is vented at
the bottom to allow the free movement of produced fluid into the
drive tube, assuring that the drive shaft bearings are always
immersed in fluid. In an embodiment, if the produced fluid is
either corrosive or prone to scale deposition, the production line
vented option can be used, as the flow rate up the drive tube could
be closely controlled so that the fluid in the drive tube would be
essentially stagnant. Thus, any potential for corrosion or scale
formation on the drive string and/or bearings is greatly reduced.
In such an embodiment, any remaining scale and corrosive components
in the resulting stagnant column of water would have minimal effect
given the lack of continuous movement.
[0057] In an embodiment, the drive tube is open to the pump outlet,
thus, when it is completely filled with liquid, the pressure in the
tube at the surface will be equal to the pump outlet pressure less
the hydrostatic pressure exerted by a static liquid column. The
pressure at the production tubing outlet at the surface will be
equal to the pump outlet pressure less the hydrostatic pressure
exerted by a static liquid column less the frictional pressure drop
due to fluid flow in the production tubing. Thus, as long as there
is flow in the tubing, the pressure at the top of the drive tube
will be greater than the surface production tubing pressure, the
difference being the pressure drop due to flowing friction. This
difference can be used to purge the gas that will naturally
accumulate at the top of the drive tube. Since the drive tube is
open to the well's production fluid, some gas and/or oil may
migrate up the drive tube during production. Eventually, the oil
and/or gas will completely displace the water in the drive tube.
The situation is more serious if gas fills even a portion of the
tube since the upper bearings can become starved of liquid
lubricant, resulting in eventual bearing failure.
[0058] In an embodiment, a drive tube can be fitted with vent line
to the production tubing outlet, and the line can be equipped with
a pressure regulator that opens when the pressure differential
between the drive tube and the production tubing exceeds a set
value. In the situation of possible accumulation of oil and/or gas
in the drive tube, the pressure setting for the pressure regulator
may need to be set after taking into account a higher than the
expected friction loss pressure drop, so that the valve opens only
after such accumulations occur. Thus, as oil and gas accumulate at
the top of the drive tube, the pressure-regulated valve can be set
to open periodically to vent some of the oil and gas from the tube,
keeping a constant amount of water in the drive tube so that the
bearings are always lubricated.
[0059] In an embodiment where neither corrosion nor scale
deposition is of great concern, then the drive tube-venting
embodiment can be used. In this embodiment, the drive tube is
vented at the bottom, but there is an additional drive tube vent
into the production tubing just below the wellhead as shown in FIG.
12. During production operations, there may be a significant
frictional pressure drop in the production tubing between the
bottom hole and the surface, due to the high rate of flow in the
production tubing. Consequently, there is a greater fluid pressure
inside the drive tube at the surface than in the adjacent
production tubing. This differential can be used to force a low
rate fluid to flow up the drive tube and out the top vent,
resulting in a continual circulation of produced fluid up the drive
tube, lubricating and cooling the bearings. Any oil and/or gas
entering the drive tube would also pass through the top vent,
eliminating the chance of gas accumulation causing lack of adequate
lubricant, as described above.
[0060] In the embodiments, an effective cooling and lubrication of
the stabilizer bearings is provided by the constant flow of water.
See, e.g., FIG. 12. Such cooling and lubrication may be critical in
deviated well situations, since the stabilizer bearings experience
heavier side loads due to the bending of the drive string. In an
embodiment, the production line venting also can provide continuous
flow of produced fluid up the drive tube to both cool the bearings
situated in that area. Further the production line venting can
provide for continuous purging of any oil and/or gas that
accumulates in the drive tube by merely opening a control valve to
allow the desired amount of liquid to continuously flow up the
drive tube and into the production flowline.
[0061] Embodiments of the present invention facilitate easier
installation of a well pump. FIG. 13 shows an example method for
installing a direct drive pump, the direct drive pump having a
drive tube and a drive rod such as the embodiments illustrated in
FIGS. 2 and 7. Generally, in an oilfield operation, a pump assembly
is installed in a well using a well service rig. The well service
rig has a derrick, draw works, and accessory equipment that allows
the running in and pulling out of tubulars and other equipment for
use in a well. The bottom hole assembly, including a multi-stage
pump, thrust bearing, and drive rod and drive tube receiver, is
attached via a connection, e.g., a threaded connection, to a length
of production tubing 1301. The length of production tubing
typically includes two joints of tubing, each 30 feet in length,
and connected together via, e.g., a threaded connection, thus
forming a stand of tubing that is about 60 feet long. The pump
assembly and single stand of tubing are lowered into the well 1302
via the well service rig for about 60 feet, and the tubing is
secured in the wellhead 1303. Another 60 foot stand of tubing is
attached 1304, via, e.g., a threaded connection, to the stand that
is secured in the wellhead and which is attached to the bottom hole
assembly. The entire assembly is lowered 1305 a further 60 feet and
another stand is attached to the production tubing. This process is
continued until the bottom hole assembly is located at the desired
depth in the well 1306, and the production tubing is secured in the
well head. Next, the drive tube, which consists of 60 foot stands
(two 30 foot joints joined via a threaded connection) of smaller
diameter tubing is inserted into the production tubing 1307, and
run to bottom in a similar fashion as the production tubing and
bottom hole assembly was run and secured in the wellhead 1308. The
drive string tube is equipped with centralizers to locate it
concentrically inside the production tubing See, e.g., FIGS. 2, 3.
The drive string is also equipped with a close fitting male stab-in
member at the bottom, which fits into the drive tube seal bore
receiver in the bottom hole assembly. This seal bore assembly
locates the drive tube so that it is centered around the drive rod
receiver within the bottom hole assembly (see, e.g., FIG. 10),
while also allowing relative vertical movement between the drive
tube and bottom hole assembly. The drive rods with stabilizers, in
50 to 75 foot stands, are then run inside of the drive tube, in a
manner similar to how the drive tube was run 1309. The drive rods
are typically 25 feet or 30 feet in length, and are attached to one
another via threaded connections. The drive rod string is run to
bottom and the splined rod connector is stabbed into the drive rod
stab-in receiver in the bottom hole assembly. See, e.g., FIG. 10.
This splined connection allows the rod to rotationally drive the
centrifugal pump but provide for relative vertical movement between
the drive rods and the bottom hole assembly. The direct drive pump
which does not use a drive tube is installed in the same manner.
The difference being that no drive tube is installed in the direct
drive pump. Instead, the drive rod string is run directly after the
bottom hole assembly and production tubing string are run to the
proper depth and secured in the well head. The drive head is then
installed such that the drive rod can be turned by the electric
motor (see, e.g., FIG. 2), thus driving the multi-stage centrifugal
pump in the bottom hole assembly 1310. The surface flow line is
attached to the well head 1311 and the pump is ready for operation.
The surface flow line can then be used to transport well fluids
lifted by the pump to any desired location, e.g., nearby storage
container, etc.
[0062] It should be understood that there exist implementations of
other variations and modifications of the invention and its various
aspects, as may be readily apparent to those of ordinary skill in
the art, and that the invention is not limited by specific
embodiments described herein. Features and embodiments described
above may be combined with and without each other. It is therefore
contemplated to cover any and all modifications, variations,
combinations or equivalents that fall within the scope of the basic
underlying principals disclosed and claimed herein.
* * * * *