U.S. patent application number 16/462913 was filed with the patent office on 2019-10-10 for electric submersible pump dual gas and sand separator.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Michael A. MURRAY, Wesley John NOWITZKI, Randy S. ROBERTS, David Linn SELF, Jared Michael TODD.
Application Number | 20190309768 16/462913 |
Document ID | / |
Family ID | 62839686 |
Filed Date | 2019-10-10 |
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United States Patent
Application |
20190309768 |
Kind Code |
A1 |
TODD; Jared Michael ; et
al. |
October 10, 2019 |
ELECTRIC SUBMERSIBLE PUMP DUAL GAS AND SAND SEPARATOR
Abstract
An electric submersible pump (ESP) dual gas and sand separator
is described. An ESP system includes a dual gas and sand separator
having a fluid flow pathway including an upward turn and a downward
turn, the upward turn separating solids from a fluid flowing
through the pathway and the downward turn separating gas from the
fluid, the dual separator including a sand sump below the fluid
flow pathway. The separator includes tubing that extends below the
ESP assembly, at least a portion of the tubing including two
concentric pipes. A dual gas and sand separating method includes
causing pumped fluid to turn from upwards to downwards and then
upwards again in a tortious pathway below the ESP assembly before
the fluid travels into a centrifugal pump intake, and collecting
solids that separate out of the multiphase fluid in a solid sump
coupled below the tortious pathway.
Inventors: |
TODD; Jared Michael;
(Edmond, OK) ; MURRAY; Michael A.; (Claremore,
OK) ; MURRAY; Michael A.; (Claremore, OK) ;
NOWITZKI; Wesley John; (Tulsa, OK) ; ROBERTS; Randy
S.; (Tulsa, OK) ; SELF; David Linn; (Laurel,
MS) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
62839686 |
Appl. No.: |
16/462913 |
Filed: |
January 11, 2018 |
PCT Filed: |
January 11, 2018 |
PCT NO: |
PCT/US2018/013269 |
371 Date: |
May 21, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62444927 |
Jan 11, 2017 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F04D 29/426 20130101;
F04D 13/10 20130101; E21B 43/38 20130101; F04D 29/708 20130101;
E21B 43/128 20130101 |
International
Class: |
F04D 29/70 20060101
F04D029/70; F04D 13/10 20060101 F04D013/10; F04D 29/42 20060101
F04D029/42; E21B 43/38 20060101 E21B043/38 |
Claims
1. An electric submersible pump (ESP) assembly comprising: a
tubular shroud separating a housing of the ESP assembly from a well
casing, the tubular shroud extending between a base of a
centrifugal pump and a location below the ESP assembly, the tubular
shroud sealed from well fluid ingress at the centrifugal pump base;
a stinger hanging below the tubular shroud, the stinger comprising:
an annular jacket, the annular jacket comprising a plurality of
inlet openings and coupled to a sand sump below the annular jacket,
a pipe inwards of the annular jacket, the pipe open at a top end
and a bottom end of the pipe, a space above the inlet openings and
between an inner diameter of the annular jacket and an outer
diameter of the pipe sealed from upward fluid flow, and an inside
of the pipe fluidly coupled to an inner diameter of the tubular
shroud.
2. The ESP assembly of claim 1, wherein the tubular shroud and
stinger define a production fluid pathway that extends through the
plurality of inlet openings in the stinger, continues downward
between the inner diameter of the annular jacket and the outer
diameter of the pipe, turns at the bottom end of the pipe and flows
upward through the inside of the pipe, continues upward through the
inner diameter of the tubular shroud, enters the pump intake and
then continues into the centrifugal pump.
3. The ESP assembly of claim 2, wherein the ESP assembly comprises
an induction motor encased in a motor housing, wherein the
production fluid flows between an outside of the motor housing and
the inner diameter of the tubular shroud as the production fluid
continues upward through the inner diameter of the tubular shroud
on the way to the pump intake.
4. The ESP assembly of claim 2, wherein gas separates out of the
production fluid when the production fluid continues downward
between the inner diameter of the annular jacket and the outer
diameter of the pipe.
5. The ESP assembly of claim 4, wherein the gas exits the stinger
and enters a casing annulus through a top row of the plurality of
inlet openings.
6. The ESP assembly of claim 2, wherein sand separates out of the
production fluid when the production fluid turns at the bottom end
of the pipe, and the sand collects in the sand sump.
7. The ESP assembly of claim 1, wherein the bottom end of the pipe
is chamfered.
8. The ESP assembly of claim 1, wherein the plurality of openings
comprise two offset rows of slots.
9. An electric submersible pump (ESP) system comprising: a dual gas
and sand separator, the dual gas and sand separator hanging below a
downhole ESP assembly from a shroud; the shroud surrounding an
inlet section of a centrifugal pump of the ESP assembly; the dual
gas and sand separator comprising a stinger, the stinger comprising
a plurality of concentric pipes and a sand sump hanging below an
outer pipe of the plurality of concentric pipes.
10. The ESP system of claim 9, wherein the outer pipe of the
plurality of concentric pipes comprises at least one inlet opening
extending through a wall of the outer pipe.
11. The ESP system of claim 10, wherein the at least one inlet
opening comprises two rows of offset slots.
12. The ESP system of claim 10, wherein the dual gas and sand
separator is configured such that fluid flows through the at least
one opening and downwards towards the sand sump, turns at the
bottom of an inner pipe of plurality of concentric pipes and flows
upward through the inside of the inner pipe.
13. The ESP system of claim 12, further comprising multiphase fluid
flowing through the dual gas and sand separator, and wherein gas
separates from the multiphase fluid as it flows downward towards
the sand sump and sand separates from the multiphase fluid as the
fluid turns upwards at the bottom of the inner pipe.
14. The ESP system of claim 13, wherein the sand collects in the
sand sump.
15. The ESP system of claim 9, wherein an inside of an inner pipe
of the plurality of concentric pipes is fluidly coupled to an inlet
of a centrifugal pump in a downstream direction from the inside of
the inner pipe towards the inlet of the centrifugal pump.
16. An electric submersible pump (ESP) system comprising a dual gas
and sand separator suspended below an ESP assembly, the dual gas
and sand separator having portions defining a fluid flow pathway
comprising a 180.degree. upward turn and a 180.degree. downward
turn, the 180.degree. upward turn configured to separate solids
from a fluid flowing through the pathway and the 180.degree.
downward turn configured to separate gas from the fluid flowing
through the pathway, the dual gas and sand separator comprising a
solid collection sump below the portions defining the fluid flow
pathway.
17. The ESP system of claim 16, wherein the dual gas and sand
separator comprises an inner tube fluidly coupled to an intake of a
centrifugal pump of the ESP assembly.
18. The ESP system of claim 16, wherein the solid collection sump
extends between twenty and five hundred feet in length.
19. The ESP system of claim 16, wherein the dual gas and sand
separator comprises a shroud, a stinger secured below the shroud
and the solid collection sump secured below the stinger.
20. An electric submersible pump (ESP) dual gas and sand separation
method comprises: pumping a multiphase fluid downhole in a well to
bring the multiphase fluid to a well surface; causing the fluid to
make a turn from upwards to downwards and a subsequent turn from
downwards to upwards in a tortious pathway below the ESP assembly
before the multiphase fluid travels into a centrifugal pump intake;
and collecting solids that separate out of the multiphase fluid in
a collection receptacle below the tortious pathway.
21. The ESP dual gas and sand separating method of claim 20,
wherein the turn from upwards to downwards separates gas from the
multiphase fluid, and wherein the subsequent turn from downwards to
upwards separates the solids from the multiphase fluid.
Description
BACKGROUND
1. Field of the Invention
[0001] Embodiments of the invention described herein pertain to the
field of submersible pump assemblies. More particularly, but not by
way of limitation, one or more embodiments of the invention enable
an electric submersible pump dual gas and sand separator.
2. Description of the Related Art
[0002] When pressure within a well, such as an oil or water well,
is not enough to force fluid out of the well, submersible pump
assemblies are used to artificially lift fluid to the surface. A
typical vertical electric submersible pump (ESP) assembly consists
of, from bottom to top, an electrical motor, seal section, pump
intake and centrifugal pump, which are all connected together with
shafts. Centrifugal pumps accelerate a working fluid through stages
of rotating impellers, which are keyed to the rotatable pump shaft.
The electrical motor supplies torque to the shafts, which provides
power to turn the centrifugal pump. The electrical motor is
generally connected to a power source located at the surface of the
well using a motor lead cable. The entire assembly is placed into
the well inside a casing. The casing separates the submersible pump
assembly from the well formation. Perforations in the casing allow
well fluid to enter the casing. These perforations are generally
below the motor and are advantageous for cooling the motor if it
can be arranged that fluid is drawn passed the outside of the motor
as it makes it way from the perforations up to the pump intake.
[0003] Many underground formations also contain well-born solids,
such as consolidated and unconsolidated sand. Induced hydraulic
fracturing or hydrofracking, commonly known as fracking, may also
cause solids such as proppant to be deposited into well bore
formations in the form of "frac" material. Whether the solids are
naturally present or consist of frac material, the hydrocarbon
laden fluid must pass through those solids on its way to the pump
intake, and ultimately to the surface. While the pump is in
operation, the hydrocarbon fluid can carry the solids through the
pump components. Such well-born solids may have severe abrasive
effects on the submersible pump components and increase the wear
during use. Abrasive wear to the pump causes inefficiency in its
operation, such as by undesirably eroding tight clearances. In
addition, sand can also plug pump pathways and openings, such as
intake filters, which can lead to pump starvation, overheating and
failure.
[0004] Care must be taken to avoid the damage caused by solids in
the produced well fluid. In the case of an ESP, a failure of the
pump or any support components in the pump assembly can be
catastrophic as it means a delay in well production and having to
remove the pump from the well for repairs. A submersible pump
system capable of removing abrasive solids from produced fluids
would be an advantage in all types of submersible assemblies.
[0005] Another challenge to economic and efficient ESP operation is
pumping gas laden fluid. For example, formations with oil often
also contain natural gas. When pumping gas laden fluid, the gas may
separate from the denser fluid due to the pressure differential
created when the pump is in operation. If there is a sufficiently
high gas volume fraction, typically about 10% or more, the pump may
experience a decrease in efficiency and decrease in capacity or
head (slipping). If gas continues to accumulate on the suction side
of the impeller it may entirely block the passage of other fluid
through the centrifugal pump. When this occurs the pump is said to
be "gas locked" since proper operation of the pump is impeded by
the accumulation of gas. As a result, careful attention to gas
management in submersible pump systems is needed in order to
improve the production of gas laden fluid from subsurface
formations.
[0006] Currently in wells with gas laden fluid, attempts are made
to remove gas either using shrouds or gas separators. Shrouds
redirect the flow of well fluid to induce gas to break away from
the liquid before the fluid enters the inlet to the pump. Gas
separators, on the other hand, sometimes serve as the pump intake
in gassy wells. Gas separators attempt to separate gas and liquid
by spinning the fluid before it continues to the pump. In wells
with high solid content, slotted screens are employed around the
pump intake ports in an attempt to remove the solids before they
enter the pump. These screens frequently become clogged or include
slots that are too large to remove smaller solid particles.
[0007] A problem that arises in wells having high concentrations of
both gas and solids is that, in addition to the aforementioned
problems, the solids reduce the effectiveness of the gas handling
equipment. For example, in assemblies employing an inverted shroud
for gas separation, the shroud can fill with sand, plugging the
inlet to the pump. Further, current equipment designed to separate
gas from well fluid is distinct from equipment employed to separate
solids. Incorporating two pieces of specialized equipment for both
gas and solid removal into an ESP assembly adds to the cost and
complexity of the pump assembly.
[0008] It would be an advantage for submersible pump assemblies
operating in both gaseous and solid-laden environments to have dual
gas and solid separation capability. Therefore, there is a need for
an improved electric submersible pump dual gas and sand
separator.
SUMMARY
[0009] Embodiments described herein generally relate to an electric
submersible pump (ESP) dual gas and sand separator. An ESP dual gas
and sand separator is described.
[0010] An illustrative embodiment of an ESP assembly includes a
tubular shroud separating a housing of the ESP assembly from a well
casing, the tubular shroud extending between a base of a
centrifugal pump and a location below the ESP assembly, the tubular
shroud sealed from well fluid ingress at the centrifugal pump base,
a stinger hanging below the tubular shroud, the stinger including
an annular jacket, the annular jacket including a plurality of
inlet openings and coupled to a sand sump below the annular jacket,
a pipe inwards of the annular jacket, the pipe open at a top end
and a bottom end of the pipe, a space above the inlet openings and
between an inner diameter of the annular jacket and an outer
diameter of the pipe sealed from upward fluid flow, and an inside
of the pipe fluidly coupled to an inner diameter of the tubular
shroud. In some embodiments, the tubular shroud and stinger define
a production fluid pathway that extends through the plurality of
inlet openings in the stinger, continues downward between the inner
diameter of the annular jacket and the outer diameter of the pipe,
turns at the bottom end of the pipe and flows upward through the
inside of the pipe, continues upward through the inner diameter of
the tubular shroud, enters the pump intake and then continues into
the centrifugal pump. In certain embodiments, the ESP assembly
includes an induction motor encased in a motor housing, wherein the
production fluid flows between an outside of the motor housing and
the inner diameter of the tubular shroud as the production fluid
continues upward through the inner diameter of the tubular shroud
on the way to the pump intake. In some embodiments, gas separates
out of the production fluid when the production fluid continues
downward between the inner diameter of the annular jacket and the
outer diameter of the pipe. In certain embodiments, the gas exits
the stinger and enters a casing annulus through a top row of the
plurality of inlet openings. In some embodiments, sand separates
out of the production fluid when the production fluid turns at the
bottom end of the pipe, and the sand collects in the sand sump. In
certain embodiments, the bottom end of the pipe is chamfered. In
some embodiments, the plurality of openings include two offset rows
of slots.
[0011] An illustrative embodiment of an electric submersible pump
(ESP) system includes a dual gas and sand separator, the dual gas
and sand separator hanging below a downhole ESP assembly from a
shroud, the shroud surrounding an inlet section of a centrifugal
pump of the ESP assembly, the dual gas and sand separator including
a stinger, the stinger including a plurality of concentric pipes
and a sand sump hanging below an outer pipe of the plurality of
concentric pipes. In some embodiments, the outer pipe of the
plurality of concentric pipes includes at least one inlet opening
extending through a wall of the outer pipe. In certain embodiments,
the at least one inlet opening includes two rows of offset slots.
In some embodiments, the dual gas and sand separator is configured
such that fluid flows through the at least one opening and
downwards towards the sand sump, turns at the bottom of an inner
pipe of plurality of concentric pipes and flows upward through the
inside of the inner pipe. In certain embodiments, the ESP system
further includes multiphase fluid flowing through the dual gas and
sand separator, and wherein gas separates from the multiphase fluid
as it flows downward towards the sand sump and sand separates from
the multiphase fluid as the fluid turns upwards at the bottom of
the inner pipe. In some embodiments, the sand collects in the sand
sump. In certain embodiments, an inside of an inner pipe of the
plurality of concentric pipes is fluidly coupled to an inlet of a
centrifugal pump in a downstream direction from the inside of the
inner pipe towards the inlet of the centrifugal pump.
[0012] An illustrative embodiment of an electric submersible pump
(ESP) system includes a dual gas and sand separator suspended below
an ESP assembly, the dual gas and sand separator having portions
defining a fluid flow pathway including a 180.degree. upward turn
and a 180.degree. downward turn, the 180.degree. upward turn
configured to separate solids from a fluid flowing through the
pathway and the 180.degree. downward turn configured to separate
gas from the fluid flowing through the pathway, the dual gas and
sand separator including a solid collection sump below the portions
defining the fluid flow pathway. In some embodiments, the dual gas
and sand separator includes an inner tube fluidly coupled to an
intake of a centrifugal pump of the ESP assembly. In certain
embodiments, the solid collection sump extends between twenty and
five hundred feet in length. In some embodiments, the dual gas and
sand separator includes a shroud, a stinger secured below the
shroud and the solid collection sump secured below the stinger.
[0013] An illustrative embodiment of an electric submersible pump
(ESP) dual gas and sand separation method includes pumping a
multiphase fluid downhole in a well to bring the multiphase fluid
to a well surface, causing the fluid to make a turn from upwards to
downwards and a subsequent turn from downwards to upwards in a
tortious pathway below the ESP assembly before the multiphase fluid
travels into a centrifugal pump intake, and collecting solids that
separate out of the multiphase fluid in a collection receptacle
below the tortious pathway. In some embodiments, the first turn
from upwards to downwards separates gas from the multiphase fluid,
and the subsequent turn from downwards to upwards separates the
solids from the multiphase fluid.
[0014] In further embodiments, features from specific embodiments
may be combined with features from other embodiments. For example,
features from one embodiment may be combined with features from any
of the other embodiments. In further embodiments, additional
features may be added to the specific embodiments described
herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] Advantages of the present invention may become apparent to
those skilled in the art with the benefit of the following detailed
description and upon reference to the accompanying drawings in
which:
[0016] FIG. 1 is a perspective view of an exemplary submersible
pump assembly with a dual gas and sand separator of illustrative
embodiments and illustrating an exemplary flow path of lifted
fluid.
[0017] FIG. 2 is a perspective view of a stinger and sand sump of
an illustrative embodiment.
[0018] FIG. 3A is a perspective view of a stinger of an
illustrative embodiment.
[0019] FIG. 3B is cross sectional view across line 3B-3B of FIG. 3A
of a stinger of an illustrative embodiment.
[0020] FIG. 3C is an enlarged view of a stinger top of an
illustrative embodiment of the stinger of FIG. 3B.
[0021] FIG. 4 is an enlarged view of the bearing supports of FIG.
3B of a dual gas and sand separator of an illustrative
embodiment.
[0022] FIG. 5 is a perspective view of a bearing support of a dual
gas and sand separator of an illustrative embodiment.
[0023] FIG. 6 is a perspective view of a system inlet of an
illustrative embodiment having exemplary round inlet openings.
[0024] FIG. 7 is a perspective view of a system inlet of an
illustrative embodiment having exemplary offset rows of slots of an
illustrative embodiment.
[0025] While the invention is susceptible to various modifications
and alternative forms, specific embodiments thereof are shown by
way of example in the drawings and may herein be described in
detail. The drawings may not be to scale. It should be understood,
however, that the embodiments described herein and shown in the
drawings are not intended to limit the invention to the particular
form disclosed, but on the contrary, the intention is to cover all
modifications, equivalents and alternatives falling within the
scope of the present invention as defined by the appended
claims.
DETAILED DESCRIPTION
[0026] An electric submersible pump (ESP) dual gas and sand
separator will now be described. In the following exemplary
description, numerous specific details are set forth in order to
provide a more thorough understanding of embodiments of the
invention. It will be apparent, however, to an artisan of ordinary
skill that the present invention may be practiced without
incorporating all aspects of the specific details described herein.
In other instances, specific features, quantities, or measurements
well known to those of ordinary skill in the art have not been
described in detail so as not to obscure the invention. Readers
should note that although examples of the invention are set forth
herein, the claims, and the full scope of any equivalents, are what
define the metes and bounds of the invention.
[0027] As used in this specification and the appended claims, the
singular forms "a", "an" and "the" include plural referents unless
the context clearly dictates otherwise. Thus, for example,
reference to a "pipe" includes one or more pipes.
[0028] "Coupled" refers to either a direct connection or an
indirect connection (e.g., at least one intervening connection)
between one or more objects or components. The phrase "directly
attached" means a direct connection between objects or
components.
[0029] As used in this specification and the appended claims,
"downstream" with respect to a downhole ESP assembly refers to the
longitudinal direction towards the wellhead. As used herein, the
"top" of a component refers to the downstream-most side of the
component.
[0030] As used in this specification and the appended claims,
"upstream" refers to the longitudinal direction deeper into the
well and/or away from the wellhead. As used herein, the "bottom" of
a component refers to the upstream-most side of the component.
[0031] As used in this specification and the appended claims, the
terms "solid," "solids," "debris" and "sand" refer interchangeably
to sand, rocks, rock particles, dirt, soils, slurries, proppant and
any other non-liquid, non-gaseous matter found in the fluid being
pumped by an artificial lift pumping system.
[0032] As used in this specification and the appended claims, the
term "sand sump" refers to a pit, hollow, receptacle and/or low
lying place that serves as a repository for sand separated from
fluid being drawn into the ESP pump of illustrative
embodiments.
[0033] So as not to obscure the invention, illustrative embodiments
are primarily described herein in terms of a downhole ESP assembly.
However, the invention is not so limited and may be equally
employed in other types of pumps, artificial lift and/or fluid
moving applications where it is desirable to separate both gas and
solid from liquid prior to the multiphase fluid's entry into the
pump and/or fluid mover.
[0034] Illustrative embodiments of the invention described herein
provide a dual gas and sand separator for an ESP downhole assembly.
Illustrative embodiments may separate at least a portion of both
gas and sand from well fluid prior to the fluid's entry into the
ESP's centrifugal pump. Illustrative embodiments may store sand in
a manner that may prevent the sand from plugging the intake of the
ESP pump and/or may avoid flushing of separated sand back into the
casing annulus. By reducing sand and gas entering the pump,
illustrative embodiments may reduce the likelihood of gas locking,
reduce abrasive damage to the pump and/or reduce clogging of pump
filters and openings. Illustrative embodiments may be simple and
inexpensive to implement since illustrative embodiments may be
employed in a single separator component, and the constituent parts
such as piping may be readily available to ESP providers and may be
premanufactured.
[0035] Illustrative embodiments may include a closed shroud around
an ESP assembly inside the well casing. The shroud may be secured
to the ESP assembly at the pump base and sealed from the ingress of
well fluid at the shroud's upper attachment point to the pump. The
shroud may extend from the pump base to below the ESP assembly,
below the ESP motor and downhole sensors. A stinger of illustrative
embodiments may be attached below the shroud. The stinger may
include two concentric pipes. The inner pipe may have a chamfered
upstream (bottom) end and an inside that is fluidly coupled to the
inside of the shroud and the inlet to the ESP's centrifugal pump.
The outer pipe (jacket) may have a wall with openings proximate the
top for fluid entry and/or gas exit, and include a bottom portion
and/or be coupled to a sand sump. The space between the outer
diameter of the inner pipe and the inner diameter of the jacket may
be sealed to block fluid flow between the stinger and the shroud in
the space.
[0036] During operation of the ESP assembly of illustrative
embodiments, fluid may enter casing perforations and travel into
the system inlet openings in the stinger jacket. Once the fluid
enters the openings in the jacket, it may fall downwards inside the
jacket, a portion of gas breaking out of the fluid at the turn
downwards. The break out gas may exit the stinger through the
openings in the stinger jacket and enter the casing annulus. The
lifted fluid may continue to travel downwards between the inner
pipe and jacket, until it reaches the bottom of the inner pipe
and/or a hole in the inner pipe. At the bottom of the inner pipe,
the fluid may turn from flowing downwards to flowing upwards, and
flow upwards inside the inner pipe. At the turn from downwards to
upwards, solids may separate out of the fluid and fall downwards
into the sand sump coupled below the jacket. After turning upwards,
the well fluid may then travel upwards into the inside of the inner
pipe, then pass into the inside of the shroud between the outer
diameter of the ESP housing and the inner diameter of the shroud,
until it reaches the pump intake. The fluid may then enter the pump
intake and continue into the pump with both a lower gas and a lower
solid content than fluid entering the casing. As the fluid passes
the motor, it may cool the motor.
[0037] FIG. 1 is an illustrative embodiment of an electric
submersible pump (ESP) assembly with dual gas and sand separator of
an illustrative embodiment. ESP assembly 100 may be located
downhole in a well below surface 105. The well may, for example, be
several hundred or a few thousand feet deep. ESP assembly 100 may
be vertical or may be slightly curved, bent and/or angled,
depending on well direction, although it is currently preferred
that the ESP assembly be arranged generally in a vertical direction
to maximize the separation benefits of illustrative embodiments.
The well may be an oil well, water well, and/or well containing
other hydrocarbons, such as natural gas, and/or another production
fluid. ESP assembly 100 may be separated from underground formation
110 by well casing 115. In an exemplary embodiment, casing 115 may
be six, seven or nine inches in diameter, or another similar
diameter. Production fluid (lifted fluid) 120 may enter well casing
115 through casing perforations 125. Casing perforations 125 may be
either above or below ESP assembly 100 and/or ESP intake 150. In
the embodiment shown in FIG. 1, casing perforations 125 are below
ESP assembly 100 and below ESP intake 150.
[0038] ESP assembly 100 may include downhole sensors 130 which may
detect, measure and/or provide information regarding motor
revolution rate, discharge pressure, vibration in one, two, or
three axes, intake pressure, discharge pressure, gauge temperature,
and/or other operating conditions to a user interface, variable
speed drive controller and/or data collection computer and/or
programmable logic controller (PLC) on surface 105. Pump flow rate
may be inferred from differential pressures when a discharge
pressure transducer is included. ESP motor 135 may be an induction
motor, such as a two-pole, three phase squirrel cage induction
motor. Components of ESP assembly 100 may be encased in ESP housing
305, which housing 305 may define the outer diameter of one or more
components of ESP assembly 100. Power cable 140 may provide power
to ESP motor 135 and/or carry data from downhole sensors 130 to
surface 105. Downstream of motor 135 may be motor protector (seal
section) 145, ESP intake 150, multi-stage centrifugal ESP pump 155
and production tubing 160. Motor protector 145 may serve to
equalize pressure and keep the motor oil separate from well fluid
120. ESP intake 150 may include intake ports and/or a slotted
screen, and serve as the intake for production fluid 120 into
centrifugal ESP pump 155. ESP pump 155 may be a multi-stage
centrifugal pump including stacked impeller and diffuser stages.
Other components of ESP assemblies may also be included in ESP
assembly 100, such as a tandem charge pump (not shown) located
between centrifugal ESP pump 155 and intake 150. Shafts of motor
135, motor protector 145, ESP intake 150 and ESP pump 155 may be
connected together (i.e., splined) and be rotated by shaft of motor
135. Production tubing 160 may carry production fluid 120 from the
discharge of ESP pump 155 towards wellhead 165.
[0039] ESP assembly 100 may include shroud 170. Shroud top 175 may
be sealed around ESP assembly 100 above ESP intake 150, such as at
the base of ESP pump 155 or on production tubing 160, such that
production fluid 120 may not enter ESP pump 155 except from the
inside of shroud 170. Shroud top 175 may be attached by a split
clamp secured around the base of ESP pump 155, ESP pump 155 and/or
production tubing 160. The clamp may seal shroud top 175 from well
fluid ingress and provide a sealed opening through which power
cable 140 may extend so as to reach motor 135 below. Shroud 170 may
extend from shroud top 175 to below downhole sensors 130, below
motor 135 and/or below the lowermost (upstream most) component of
ESP assembly 100. In some embodiments, shroud 170 may extend at
least about five feet below the bottom-most component of ESP
assembly 100, depending on the depth of the well, extending below
ESP motor 135 and/or below downhole sensors 130.
[0040] Stinger 180 may be attached to shroud bottom 185 of shroud
170. A stinger of illustrative embodiments is illustrated in FIG.
2. Stinger 180 may be secured to shroud bottom 185 by top threads
200, screws, bolts or another attachment means known to those of
skill in the art of ESPs. Stinger 180 may extend about twenty to
forty feet below shroud bottom 185, depending on the depth of the
well in which ESP assembly 100 is placed. Stinger 180 may include
two and/or at least two concentric pipes and/or tubes: outer pipe
(jacket) 205 and inner pipe 210. Outer pipe 205 may have a larger
diameter than inner pipe 210 and surround inner pipe 210 with a
space between them. Outer pipe 205 and inner pipe 210 may both be
hollow to create pathways for fluid flow both inside and outside
the pipes 205, 210.
[0041] Turning to FIG. 3C, FIG. 6 and FIG. 7, the top portion of
outer pipe 205 may be a system inlet and/or system inlet portion,
section and/or piece and include inlet openings 215. Inlet openings
215 may be proximate stinger top 220, such as within 3.0 inches,
5.0 inches, 6.0 inches, 1.0 foot or another similar distance from
stinger top 220, and may be slots, circular openings, square
openings, oval openings or another shape of opening. FIG. 6
illustrates exemplary round inlet openings 215, and FIG. 7
illustrates exemplary slotted inlet openings 215. Inlet openings
215 may be arranged in one, two or more rows 300. Where there are
multiple rows 300 of openings 215, openings 215 in adjacent rows
300 may be offset from one another as illustrated in FIG. 7. In an
illustrative embodiment, there may be six slot-shaped openings 215
per row 300, with slots in adjacent rows 300 evenly spaced apart
and rotated 30.degree., for example. Inlet openings 215 may assist
gas separation, such as separation of natural gas from oil or other
fluid hydrocarbons. Where two or more rows 300 of openings 215 are
employed, a lower row of slots 215 may allow for fluid entry, and
an upper row of offset openings 215 may allow for separated gas to
exit jacket 205 rather than build up on the inside of the inlet
piece (the top portion 220 of outer pipe 205). In some embodiments,
where inlet openings 215 are non-circular in shape, for example
slots, the slots may be slanted and/or tilted from
longitudinal.
[0042] In some embodiments, sand sump 225 may be attached below,
coupled to and/or may form a closed bottom of stinger 180.
Referring to FIG. 2 and FIG. 3A, sand sump 225 may be a blind piece
threaded on stinger bottom threads 310 and/or attached to the
bottom of stinger 180. Sand sump 225 may be closed on a bottom end
and may form solid collection receptacle 230 for sand and/or other
solids falling from inside stinger 180. The bottom end of sand sump
225 may include and/or be formed by cap 315 to prevent sand from
falling back into the casing annulus. In certain embodiments, sand
sump 225 may be a length of tube and/or pipe threaded, bolted
and/or attached to the bottom of stinger 180. Sand sump 225 may be
a collection receptacle, repository and/or reservoir between twenty
and five-hundred feet long that may collect sand that falls out of
lifted production fluid 120 and keep the sand from moving into the
casing annulus.
[0043] The space at stinger top 220 above inlet openings 215 and
between inner pipe 210 and outer pipe 205, may be sealed from well
fluid 120. Plate 235 may be welded on and/or between the inner
diameter of jacket 205 and the outer diameter of inner pipe 210 to
form the seal to well fluid. Plate 235 may be disc shaped with a
central opening so as to surround inner pipe 210 and securely block
the area between inner pipe 210 and outer pipe 205 at and/or
proximate the connection between shroud 170 and stinger 180 and/or
between inner pipe 210 and outer pipe 205 above inlet openings 215.
Plate 235 may prevent production fluid 120 located between inner
pipe 210 and outer pipe 205 from moving upwards inside of shroud
170, and instead force this production fluid 120 to flow downwards
between inner pipe 210 and outer pipe 205 before turning upwards
inside of inner pipe 210.
[0044] Inner pipe 210 may be smaller in diameter and shorter in
length than outer pipe 205, for example inner pipe 210 may be about
two inches shorter, five inches shorter, ten inches shorter than
outer pipe 205, or another similar length difference. Inner pipe
210 may hang below and/or be welded and/or attached to plate 235 on
an upper end and/or side of inner pipe 210, and may have open
bottom end 240 and/or may have a hole for fluid entry on a bottom
portion and/or lower side. Inner pipe 210 bottom end 240 may be
chamfered, slanted, stepped and/or angled, such as at a 30.degree.,
45.degree. or 60.degree. angle, or another similar angle. Chamfered
bottom end 240 may create a void and keep bottom end 240 unblocked
from debris as the debris accumulates in solid collection
receptacle 230 and/or sand sump 225. Supports 245 may be
distributed and/or spaced along the length of outer pipe 205,
between inner pipe 210 and outer pipe 215. Referring to FIG. 3B,
FIG. 4 and FIG. 5, supports 245 may be bearings with apertures 500
that allow production fluid 120 to flow through supports 245
without impeding flow rate. Supports 245 may, for example, be
spaced every 10 feet or every 15 feet, as needed to provide support
for the long, thin stinger 180.
[0045] Pipes for shroud 170, stinger 180 and/or sand sump 225 may
be sections of twenty-foot-long pipe and/or tubing that is
threaded, bolted and/or otherwise attached together to achieve the
desired length. Sections of pipe having other lengths may also be
employed depending on the supplies that are readily available to
those in the ESP industry.
[0046] Shroud 170 and stinger 180 may form a fluid flow pathway for
production fluid 120 that induces both gas and solid to separate
out of lifted fluid 120 as lifted fluid 120 enters casing 115 and
travels from perforations 125 to ESP intake 150. Returning to FIG.
1, lifted fluid 120, which may contain gas (such as natural gas)
and solid (such as sand, rock, dirt and/or other debris), may enter
casing perforations 125. If, as shown in FIG. 1, perforations 125
are below ESP assembly 100, lifted fluid 120 may enter perforations
125 and travel upwards between well casing 115 and the outer
diameter of sand sump 225 and/or the outer diameter of outer pipe
(jacket) 205 towards system inlet openings 215. When lifted fluid
120 reaches inlet openings 215 in jacket 205, lifted fluid 120 may
enter system inlet openings 215 and turn from flowing upwards to
flowing downwards. Making a 180.degree. turn or about a 180.degree.
turn, lifted fluid 120 may travel downwards between the inner
diameter of jacket 205 and the outer diameter of inner pipe 210. As
lifted fluid 120 makes its turn from flowing upwards to downwards,
gas bubbles 190 may break out of lifted fluid 120. Where two or
more rows 300 of system inlet openings 215 are employed, denser
(gas poor) lifted fluid 120 may primarily enter the lower or lowest
row, while less dense, gas rich fluid may primarily exit from the
uppermost row of openings 215. Lifted fluid 120 may flow downward
until it reaches bottom end 240 of inner pipe 210. At bottom end
240, lifted fluid 120 may turn 180.degree. from flowing downwards
to flowing upwards inside inner pipe 210. As lifted fluid 120 makes
its turn from downwards to upwards, sand and/or solids 195 may fall
out of lifted fluid 120 and drop into solid collection receptacle
230 and/or sand sump 225, which may catch and confine solids 195.
Production fluid 120 may then continue up along the inside of inner
pipe 210, flow into the inside of shroud 170, along the outside of
motor housing 305 to cool ESP motor 130. Lifted fluid 120 may
continue to flow between the housing 305 of ESP assembly 100 and
the inner diameter of shroud 170 to ESP intake 150. At ESP intake
150, lifted fluid 120 may enter ESP pump 155 and be carried through
production tubing 160 to surface 105.
[0047] Using the system of illustrative embodiments, production
fluid 120 entering ESP pump 155 and/or flowing through production
tubing 160 may have lower gas and lower solid content than fluid
entering casing perforations 125, as a result of the tortuous
pathway provided by stinger 180 and shroud 170. As lifted fluid 120
turns, gravity may assist heavier phases to travel downward, while
lighter phases travel upward, serving to separate the solid, liquid
and gas. In this manner, higher concentrations of desirable liquid
such as oil or other liquid hydrocarbons may travel through pump
155 to the exclusion of undesirable gas and solid, decreasing the
risk of gas locking, plugging or abrasive damage from gas and
solid.
[0048] If perforations 125 are above ESP intake 150, lifted fluid
120 may enter casing perforations 125 and travel downwards between
well casing 115 and shroud 170 until lifted fluid 120 reaches
system inlet openings 215 in stinger 180. As production fluid 120
travels downwards from casing perforations 125 to inlet openings
215, gas 190 may separate out of lifted fluid 120, and then
continue through the flow pathway inside stinger 180 as described
above. Lifted fluid may pass housing 305 of motor before entering
pump intake 150, which may keep motor 135 cool.
[0049] Shroud 170 may be steel or another strong, non-corrosive
material and capable of supporting several hundred feet of shroud
170, stinger 180 and sand sump 225. Supports 245 may be bearings
including apertures 500 large enough so as not to impede flow rate
of production fluid 120.
[0050] An electric submersible pump (ESP) dual gas and sand
separator has been described. Further modifications and alternative
embodiments of various aspects of the invention may be apparent to
those skilled in the art in view of this description. Accordingly,
this description is to be construed as illustrative only and is for
the purpose of teaching those skilled in the art the general manner
of carrying out the invention. It is to be understood that the
forms of the invention shown and described herein are to be taken
as the presently preferred embodiments. Elements and materials may
be substituted for those illustrated and described herein, parts
and processes may be reversed, and certain features of the
invention may be utilized independently, all as would be apparent
to one skilled in the art after having the benefit of this
description of the invention. Changes may be made in the elements
described herein without departing from the scope and range of
equivalents as described in the following claims. In addition, it
is to be understood that features described herein independently
may, in certain embodiments, be combined.
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