U.S. patent application number 14/909838 was filed with the patent office on 2016-06-23 for downhole compressor for charging an electrical submersible pump.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES INC.. Invention is credited to Lonnie Bassett, Jimmy D. Hardee, Kenneth W. Parks.
Application Number | 20160177684 14/909838 |
Document ID | / |
Family ID | 52628785 |
Filed Date | 2016-06-23 |
United States Patent
Application |
20160177684 |
Kind Code |
A1 |
Parks; Kenneth W. ; et
al. |
June 23, 2016 |
DOWNHOLE COMPRESSOR FOR CHARGING AN ELECTRICAL SUBMERSIBLE PUMP
Abstract
Downhole Electric Submersible Pumps (ESP) in a production string
often experience gas lock caused by free gas present in the
production liquids which reduces the intake pressure below
operating parameters of the ESP. A compressor is disclosed for
compressing production fluid prior to feeding the production fluid
into an ESP intake. The compression entrains or dissolves free gas
into the production liquid, reducing the risk of gas lock of the
ESP. The compression increases production fluid pressure to within
the operating pressure of the ESP intake, to a selected pressure,
or to above the free gas bubble point.
Inventors: |
Parks; Kenneth W.; (Perkins,
OK) ; Hardee; Jimmy D.; (Moore, OK) ; Bassett;
Lonnie; (Missouri City, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES INC. |
Houston |
TX |
US |
|
|
Family ID: |
52628785 |
Appl. No.: |
14/909838 |
Filed: |
September 4, 2013 |
PCT Filed: |
September 4, 2013 |
PCT NO: |
PCT/US2013/058021 |
371 Date: |
February 3, 2016 |
Current U.S.
Class: |
166/369 ;
166/66.4 |
Current CPC
Class: |
E21B 43/128 20130101;
E21B 43/38 20130101 |
International
Class: |
E21B 43/12 20060101
E21B043/12; E21B 43/38 20060101 E21B043/38 |
Claims
1. A method of producing fluid from a subterranean well having a
wellbore extending through a hydrocarbon-bearing formation, the
method comprising the steps of: positioning at a downhole location
in the wellbore a work string having an electric motor, a
compressor assembly, and an Electric Submersible Pump (ESP);
operating the compressor assembly and the ESP using the electric
motor; pumping production fluid from the formation and into an
interior passageway of the work string, the production fluid having
both free gas and production liquid therein; compressing the
production fluid using the compressor assembly, and entraining or
dissolving at least a portion of the free gas into the production
liquid; and feeding the compressed production fluid to an intake of
the ESP.
2. The method of claim 1, wherein the step of compressing further
comprises compressing the production fluid to an intake pressure
within the operating range of the ESP intake.
3. The method of claim 1, wherein the step of compressing further
comprises compressing the production fluid by between about 8 psi
(55 kPa) and 60 psi (414 kPa).
4. The method of claim 1, wherein the step of compressing further
comprises compressing the production fluid to a pressure above the
free gas bubble point at the downhole location.
5. The method of claim 1, wherein the step of compressing further
comprises compressing the production fluid in multiple stages in
the compressor assembly, and wherein each of the multiple stages
compresses the production fluid by between about 8 psi (55 kPa) and
32 psi (221 kPa).
6. The method of claim 1, wherein the compressor assembly is
positioned in the string between the electric motor and the
ESP.
7. The method of claim 1, further comprising the step of pumping
the compressed production fluid to the surface.
8. The method of claim 1, wherein the compressor assembly includes
a rotary compressor element attached to a compressor drive shaft,
and further comprising the step of driving the rotary compressor
drive shaft by a drive shaft of the electric motor.
9. The method of claim 1, further comprising the step of separating
at least some free gas from the production fluid using a gas
separator tool prior to the step of compressing the production
fluid using the compressor assembly.
10. The method of claim 1, wherein the compressor assembly allows
fluid flow therethrough without fluid flow restriction.
11. The method of claim 1, wherein the step of compressing further
comprises the step of supporting a drive shaft of the compressor
assembly with at least one bearing.
12. The method of claim 11, wherein the at least one bearing
comprises a corrosion-resistant bushing.
13. The method of claim 1, wherein the step of compressing the
production fluid using the compressor assembly, further comprises
rotating a helical compressor blade within a compressor
tubular.
14. The method of claim 13, wherein a clearance between the helical
compressor blade and the compressor tubular is minimized.
15. The method of claim 13, wherein all production fluid in the
interior passageway is compressed in the compressor assembly.
16. An apparatus for lifting production fluid from a subterranean
wellbore extending through a hydrocarbon-bearing formation to the
surface, the apparatus comprising: an Electrical Submersible Pump
(ESP) having a fluid intake; a compressor having at least one
compressor stage for compressing production fluid, the compressor
stage having a fluid discharge in fluid communication with the ESP
fluid intake, a generally helical compressor blade mounted for
rotation in a generally cylindrical chamber, and wherein the
compressor blade entrains or dissolves a free gas component of a
production fluid into a liquid component of the production fluid;
and an electrical motor for powering the ESP and compressor.
17. The apparatus of claim 16, further comprising a plurality of
adjacent compressor stages arranged in series, with each compressor
stage discharging fluid to an intake of an adjacent compressor
stage or to the ESP intake.
18. The apparatus of claim 17, wherein the plurality of compressor
stages, in combination, increase pressure of the production fluid
to a pressure within the operating range of the ESP intake.
19. The apparatus of claim 16, wherein each compressor stage
increases production fluid pressure by between about 8 psi (55 kPa)
and 32 psi (221 kPa).
20. The apparatus of claim 16, wherein the one or more compressor
stages increase production fluid pressure by between about 8 psi
(55 kPa) and 60 psi (414 kPa).
21. The apparatus of claim 16, wherein a compressor stage further
comprises at least one compressor shaft operably connected to a
drive shaft of the electric motor, and at least one compressor
shaft bearing.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] None.
FIELD OF INVENTION
[0002] The disclosure generally relates to production of
hydrocarbon-bearing fluids from a wellbore extending through a
subterranean reservoir. More particularly, the disclosure addresses
apparatus and methods for compressing produced fluids having both
liquid and free gas components prior to intake into an electrical
submersible pump.
BACKGROUND OF INVENTION
[0003] In the production of hydrocarbons from a wellbore extending
through a hydrocarbon-bearing zone in a reservoir, a production
string or tubing is positioned in the wellbore. A production string
can include multiple downhole tools, pipe sections and joints, sand
screens, flow and inflow control devices, etc. To pump production
fluid to the surface, an electrical submersible pump (ESP), powered
by an electric motor through a drive shaft, is positioned downhole
in the wellbore. Electrical power is usually provided from a
surface source by a power cable extending to the downhole electric
motor. Additional tools used in conjunction with an ESP and
electric motor include seal subassemblies, protectors, sensor
assemblies, gas separators, additional pumps, standing valves, etc.
The electric motor powers the pumps, separators, etc., via a drive
shaft connected to the rotary elements of these devices.
[0004] A submersible pump can see dozens of shut-offs each year for
various reasons. Unwanted and nuisance shut-offs include those
caused by gas lock, a condition in pumping and processing equipment
caused by induction of free gas. The presence of compressible gas
interferes with operation of the pump, thereby preventing intake of
production fluid. The production fluid often contains two or more
fluids. Gas can be found dissolved in the production fluid or
merely mixed, in a gaseous phase as free gas, with production
liquids. The free gas can exist in situ in the reservoir or can
evolve during production as pressure drops below the bubble
point.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] For a more complete understanding of the features and
advantages of the present invention, reference is now made to the
detailed description of the invention along with the accompanying
figures in which corresponding numerals in the different figures
refer to corresponding parts and in which:
[0006] FIG. 1 is a schematic view of an exemplary well system
utilizing an embodiment of a compressor assembly disclosed
herein;
[0007] FIG. 2 is a schematic partial view of an exemplary tubing
string having various downhole tools thereon, including a
submersible pump and motor for use in conjunction with a compressor
assembly according to the disclosure; and
[0008] FIG. 3 is a cross-sectional, schematic view of an exemplary
compressor assembly according to an aspect of the disclosure.
[0009] It should be understood by those skilled in the art that the
use of directional terms such as above, below, upper, lower,
upward, downward and the like are used in relation to the
illustrative embodiments as they are depicted in the figures, the
upward direction being toward the top of the corresponding figure
and the downward direction being toward the bottom of the
corresponding figure. Where this is not the case and a term is
being used to indicate a required orientation, the Specification
will state or make such clear.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0010] While the making and using of various embodiments of the
present disclosure are discussed below, a practitioner of the art
will appreciate that the disclosure provides concepts which can be
applied in a variety of specific embodiments and contexts. The
specific embodiments discussed herein are illustrative of specific
ways to make and use the disclosed apparatus and methods and do not
limit the scope of the claimed invention.
[0011] As used herein, the words "comprise," "have," "include," and
all grammatical variations thereof are each intended to have an
open, non-limiting meaning that does not exclude additional
elements or steps. It should be understood that, as used herein,
"first," "second," "third," etc., are arbitrarily assigned, merely
differentiate between two or more items, and do not indicate
sequence. Furthermore, the use of the term "first" does not require
a "second," etc.
[0012] The terms "uphole" and "downhole," "upward" and "downward,"
and the like, refer to movement or direction with respect to the
wellhead, regardless of borehole orientation. The terms "upstream"
and "downstream" refer to the relative position or direction in
relation to fluid flow, irrespective of the borehole orientation.
Although the description may focus on particular means for
positioning tools in the wellbore, such as a tubing string, coiled
tubing, or wireline, those of skill in the art will recognize where
alternate means can be utilized. Directional terms, such as "above"
and "below" may also be used with respect to the Figures as shown
and so do not limit to the orientation of the assembly or tool in
use.
[0013] FIG. 1 is a schematic illustration of a well system,
indicated generally 10, having a gas compressor assembly according
to an embodiment of the disclosure. A wellbore 12 extends through
various earth strata, including at least one production zone 20.
Exemplary wellbore 12 has a substantially vertical section 14 and a
substantially deviated section 18, shown as horizontal, which
extends through a hydrocarbon-bearing subterranean zone 20. As
illustrated, the wellbore is cased with a casing 16 along an upper
length. The wellbore is open-hole along a lower length. The
disclosed apparatus and methods will work in various wellbore
orientations and in open or cased bores.
[0014] Positioned within wellbore 12 and extending from the surface
is a production tubing string 22. Typically the production tubing
string is hung from or attached to the casing or wellhead. The
production tubing string 22 provides a conduit for production
fluids to travel from the formation zone 20 up to the surface.
Positioned within the string 22 in various production intervals
adjacent to the zone 20 are a plurality of production tubing
sections 24. Annular isolation devices 26, such as packers, provide
annular seals to fluid flow and differential pressure in the
annulus defined between the production tubing string 22 and the
casing 16. The areas between adjacent isolation devices 26 define
production intervals.
[0015] In FIG. 1, the production tubing sections 24 include sand
control capability such as sand control screen elements to allow
production fluid to flow therethrough but filter particulate matter
of sufficient size. Other tools and mechanisms can be used in
conjunction with the production string along the production zone,
such as flow control devices, autonomous flow control devices,
check valves, protective shrouds, sliding sleeve valves, etc. Such
elements are well known in the industry.
[0016] The production string allows production fluid to enter the
string. The production fluid can have multiple components, such as
oil, water, natural gas and other gases, in varying proportions.
Further, the composition of the production fluid can vary between
production intervals. The term "natural gas" as used herein means a
mixture of hydrocarbons and varying quantities of non-hydrocarbons
that exist in a gaseous phase at room temperature and pressure. The
term does not indicate that the natural gas is in a gaseous phase
at the downhole location of the inventive systems. Where it is
intended to refer to a substance in a gaseous phase, the terms
"free gas," "gaseous phase," or similar, is used. It is to be
understood that at formation pressure and temperature, natural gas
may exist dissolved in a liquid or mixed with a liquid. Such
natural gas can evolve to a gaseous phase, for example, in the
production string under lower pressures or temperatures. The
disclosed apparatus and methods are useful to entrain or dissolve
evolved free gas into the liquid components of the production
fluid.
[0017] The production tubing string seen in FIG. 1 also includes an
exemplary and schematic "tool stack" 28 or series of tools for
managing production fluid downhole and pumping production fluid to
the surface. The tools presented are exemplary, non-limiting, and
are discussed with further respect to FIG. 2.
[0018] FIG. 2 is a schematic view in elevation of an exemplary
tubing string having various downhole tools thereon, including a
submersible pump and motor for use in conjunction with a gas
compressor assembly according to the disclosure.
[0019] The tubing string 30 includes multiple downhole tools
connected to one another and positioned below a string of tubulars
32 extending to the surface. The exemplary tubing string 30
includes a sensor assembly 34, an electric motor assembly 36, a
seal subassembly 38, a protector assembly 40, a gas separator
assembly 42, a gas compressor assembly 44, and an electrical
submersible pump assembly 46. Additional tools can be employed,
including multiple pumps, separators, and protectors. The tools are
connected to one another using threaded connections or other
connection mechanisms. Attached to and extending below the
illustrated string is a production string extending through one or
more production zones of the reservoir and typically having sand
screens, flow control devices, inflow control devices, valves, and
the like, and into which production fluid from the reservoir flows.
The ESP assembly pumps the production fluid to the surface via
tubulars 32.
[0020] The sensor assembly 34 can be of various types for measuring
various downhole environmental or motor characteristics. Preferably
the sensor assembly includes pressure and temperature sensors.
Measurements are conveyed to the surface by wire or wirelessly,
providing the motor operator data for use in controlling the motor.
A preferred sensor assembly includes a surface transceiver module,
a surface safety choke, downhole temperature and pressure sensors,
and various adapters, connectors, and power sources. The sensors
are connected to the ESP motor 50. A preferred sensor assembly
includes a temperature sensor for measuring fluid temperature, a
motor oil temperature sensor, and motor winding temperature sensor.
A pressure sensor measures fluid pressure at the sensor location.
Optionally, a vibration sensor, measuring vibration on three axes,
is also present. The transceiver module provides power to and
receives measurement data from the sensors. The measurements are
conveyed to the surface. Preferably, the system automatically shuts
down when measurements exceed a pre-determined and pre-programmed
maximum. Sensor systems are commercially available, such as the
sensor systems sold as Global or Halliburton Artificial Lift Sensor
Systems, available from Halliburton Energy Services, Inc.
[0021] The electric motor assembly 36 includes a housing 48 and a
rotary electric motor 50 having a drive shaft 52 extending
therefrom. The electric motor is powered by electricity delivered
along power cable 54 extending from the surface. The cable is
typically disposed in a protective conduit and can run either along
the interior or exterior of the string. Electric ESP motors are
commercially available, for example, from Halliburton Energy
Services, Inc. The motor specifications are selected based on
operating and well conditions as will be understood by those of
skill in the art. The ESP motor 50 is connected to the sensor
system and is typically controlled by a motor operator and has
selected automatic shut-offs based on sensor data. The drive shaft
52 extends from the upper end of the motor and drives the
separators, compressors, and ESPs on the production string.
[0022] The seal sub 38 and protector 40, sometimes also referred to
as a seal, can serve to prevent production fluid or contaminants
from entering the ESP motor 36 by equalizing interior and exterior
pressure, provide a dielectric or other acceptable motor oil
reservoir, conduct heat away from the motor, and compensate for
pressure to absorb thermal expansion. A thrust bearing accepts
fluid column load upon start-up and absorbs axial load of the ESP
pump 46. Protectors are available in varying sizes and weight
specifications and varying configurations, including labyrinth,
pre-filled, single, double and modular bag, or combinations
arranged in series or parallel. Further, models are available for
high-load thrust bearing and high-strength shaft. Protectors are
commercially available from Halliburton Energy Services, Inc. One
or multiple seals or protectors can be employed on an ESP
production string.
[0023] The gas separator assembly 42 is positioned up-hole from the
protector 40, and, like the protector, can be employed as a single
unit or multiple stacked units. A gas separator typically imparts a
rotation to the production fluid to liberate free gas from the
production fluid. The free gas is then vented to the wellbore
annulus via one or more outlets. This reduces produced free gas,
disposal of unwanted gas production, workload of the ESP and ESP
motor, and the volume of production necessary to produce a given
quantity of oil. The separator is driven by the ESP motor 36 via
drive shaft. Gas separators are known in the art and commercially
available, for example, from Halliburton Energy Services, Inc.
[0024] The gas compressor assembly 44 is positioned between the
separator 42 and ESP assembly 46. The gas compressor assembly 44 is
discussed in detail below with reference to FIG. 3. Generally, the
compressor receives production fluid through an intake and, via
centrifugal forces, compresses it to reduce or eliminate free gas
in the fluid. The compressor also raises fluid pressure prior to
discharge into the ESP 46 such that the ESP intake is "pre-charged"
or "charged" to a pressure within its operating range. The
centrifugal force produced by the compressor entrains free gas into
a gas-liquid mixture and dissolves gas into the production liquid.
The compressor is preferably powered by the ESP motor via a drive
shaft although alternative power sources can be applied. Production
fluid entering the compressor proceeds through multiple compressor
stages, with fluid pressure increased at each stage. Stages are
arranged in series to produce a desired fluid pressure upon
discharge to the ESP intake.
[0025] Further, the compressors provide increased fluid pressure
without restricting fluid flow; that is, the compressor does not
utilizing a restrictor plate, orifice plate, back-pressure device,
diffuser, or other mechanism to restrict fluid flow. Where such
mechanisms are used, the restriction becomes a high-wear point and
is susceptible to failure due to erosion, especially when the
production fluid a high sand content. Erosion can result in cutting
of the tool in two, with a resultant loss of the lower portion of
the tool and any tools connected below. A fishing trip to retrieve
the dropped string is expensive and time consuming. Further, such
restrictions tend to plug with debris, such as rubber from
previously run units. The compressor 44 handles debris more easily,
eliminates high-erosion points at restrictions, reduces the
likelihood of failure due to erosion, and prolongs the useful life
of the tool. The compressor design does not restrict or limit fluid
flow, or hydrocarbon production, to increase fluid pressure, as
will be seen in relation to FIG. 3.
[0026] The ESP assembly 46 pumps production fluid to the surface.
The ESP intake receives fluid from the last sequential compressor
44 at a pressure within the operating limits of the ESP,
eliminating or reducing the risk of gas lock. The ESP is preferably
rotated by a drive shaft powered by the motor 36. Alternate power
sources can be employed. For centrifugal ESPs, the number of stages
determines the total lift provided and determines the total power
required for operation. Sensors and instrumentation can be employed
to provide operating condition data to the operator or for
automatic operation. For example, automatic shut-down sensors can
be used to limit potential damage from unexpected well conditions.
ESP specifications include a minimum fluid pressure requirement at
the pump intake. The compressor 44 (or multiple compressors in
series) is selected to provide production fluid to the ESP intake
within its operating range.
[0027] FIG. 3 is a cross-sectional schematic view of an exemplary
compressor assembly according to an aspect of the disclosure. An
exemplary compressor 60 is seen having three stages or sections
62a-c arranged in series. Each stage increases the pressure of the
production fluid. As an example, the first compressor stage 62a
increases pressure by 8 psi (55 kPa), the second compressor stage
62b further increases pressure by 16 psi (110 kPa), and the third
compressor stage 62c further increases pressure by 24 psi (165
kPa), resulting in a total increase across the compressor of
approximately 48 psi (331 kPa). Additional stages, or stages
increasing the pressure by greater amounts, can be employed to
achieve higher total increase of fluid pressure. For example, in a
preferred embodiment, the pressure is raised by about 16 psi (110
kPa) to 65 psi (448 kPa), and more preferably by about 40 psi (276
kPa) to 60 psi (414 kPa). The stages are selected to increase the
production fluid pressure to a pressure within the operating range
of the ESP, thereby preventing gas lock. Additional or fewer stages
can be employed based upon required ESP intake pressure.
[0028] A tubular compressor housing 68, preferably generally
cylindrical as shown, is attached to a base assembly 70 and a head
assembly 72 via lock plates 74. The lock plates can be replaced or
supplemented with other connection mechanisms, such as threaded
connectors, pins, welds, and the like. A compression tubular 76,
made-up of a plurality of tubulars 76a-c, is positioned interior to
the housing 68. The compressor, in this embodiment, has three
compressor stages 62a-c, although fewer or more can be used. Above
and below each stage 62 is preferably positioned a shaft support
assembly 78 for supporting compressor shaft 80 which extends the
length of the compressor 60. The compressor housing 68 is
preferably made of corrosion-resistant material such as carbon
steel or 9 chrome 1 molly. The compression tubular 76 is preferably
made of stainless steel or other material having the strength
required to prevent collapse of the tool assembly.
[0029] The base assembly 70 and head assembly 72 are each comprised
of a generally tubular housing which can be connected to tools or
additional tubulars, such as by bolt assemblies 82 and 84,
respectively. Alternate connections can be used as are known in the
art. The base assembly defines an interior passageway 86, forming
an intake 88 for the compressor assembly, providing fluid
communication with a tool below, such as gas separator 42. The base
interior passageway 86 delivers fluid into the intake of the first
compressor stage 62a. Similarly, the head assembly 72 defines
interior passageway 90, having an intake for receiving fluid from
the third compressor stage 62c. The head assembly forms a discharge
outlet 92 for the compressor assembly, which delivers compressed
fluid from the third compressor stage 62c to a tool or tubular
positioned above, such as ESP assembly 46.
[0030] The rotary shaft 80 extends the length of the compressor
assembly and causes rotation of each of the three stages 62a-c. The
shaft is supported by multiple support assemblies 78a-d. At the
upper and lower ends of the shaft are connections 94 for connection
to similar shafts positioned in adjacent tools, such as gas
separator 42 and ESP assembly 46. The shaft can be specialized for
high-torque systems and is preferably of corrosion-resistant
material. The shaft can be monolithic or formed of several
connected shaft components. The shaft is driven by the drive shaft
52 of the electric motor 50.
[0031] The three stages 62a-c are of similar construction and
design. The first stage 62a is discussed in detail, with the
remaining stages having similar components and functions. The first
stage 62a has a helical blade 100a extending radially outward from
a compressor sleeve 102a. The sleeve 102a forms a tubular and is
positioned about and attached to a section of the shaft 80.
(Alternately, the helical blade can be formed about a portion of
the shaft itself.) The rotary blade and sleeve can be formed of a
plurality of adjacent units for ease of manufacture and assembly.
Rotation of the shaft 80 results in rotation of the sleeve 102a and
helical blade 100a. Production fluid received from the base
assembly passageway 86 is received into the first stage, where the
rotation of the helical blade 100a causes the fluid to rotate,
thereby increasing the fluid pressure. Existent free gas in the
production fluid is dissolved into or entrained with production
liquids. The pressurized fluid is then output to a subsequent
stage, such as stage 62b, for further treatment, or through the
discharge head passageway 90 to a tool assembly positioned above,
such as ESP 46. The fluid pressure is preferably increased by an
incremental amount such that the stage remains relatively small.
For example, an exemplary fist stage 62a is approximately four
inches in diameter, twelve inches in length, and imparts a pressure
increase of approximately 8 psi (55 kPa).
[0032] The helical blade 100a extends radially outward from the
sleeve 102a (or shaft). The blade is "wrapped" about the sleeve,
forming a helical shape. The blade appears to be wrapped although
other manufacturing methods (e.g., casting) can be used to make the
unit. The stage is specifically designed to increase fluid
pressure, or add lift or head. To that end, the compressor helical
blade 100a is positioned in the interior passageway 104a defined by
the compression tubular 76a, with a relatively small clearance. For
example, in a preferred embodiment where the compressor helical
blade is inserted into a tube, the radial clearance is about 0.144
inches (0.366 cm) in a 3.75 inch (9.53 cm) diameter bore. In
another preferred embodiment, the compressor blade is positioned in
a honed bore, allowing for better tolerances and reduced
clearances. For example, in a honed bore a preferred clearance is
approximately 0.003 inches (7.62 mm) in a 3.75 inch (9.53 cm)
diameter bore. The tight clearance reduces annular bleed-by of
gaseous and liquid fluids which, if present, decreases the
effectiveness and the head added to the fluid by the compressor
helical blade. The increased effectiveness allows an equivalent
amount of head to be added to the production fluid using a lower
motor rate (rpm), thereby saving energy, reducing operating
temperatures of the motor, decreasing burn-out, etc. In a preferred
embodiment, the compressor blade is operated in a range of 3500 to
4500 rpm using an electric motor positioned downhole. In addition
to reducing bleed-by due to excessive blade clearance, the blade is
mounted in the only tubular through which the production fluid
flows at this section of the string. That is, there is no annular
space between the compression tube 76a and the housing 68 through
which fluid may flow or bypass the compressor blade. Finally, the
preferred embodiment is difficult to impossible to plug during use
with coal fines, sand, etc. The helical compressor blade will
elevate or move fines and the like during rotation. The tight
radial clearance will not allow debris accumulation along the
compression tube wall. Additionally, the helical blade 100 does not
flatten out into substantially vertical, radially extending paddles
at any point. Such paddles create a fluid vortex, agitate the
fluid, and decreases the effectiveness of the blade in increasing
fluid pressure or lift. For a cross-reference, see US Patent
Application Publication 2012/0269614, to Bassett, which is hereby
incorporated for all purposes.
[0033] The second stage 62b and third stage 62c operate in a
similar fashion, each causing rotation of the production fluid,
incrementally increasing the fluid pressure, and dissolving or
entraining existent free gas. In an exemplary embodiment, the
second stage imparts an additional 16 psi (110 kPa) and the third
stage imparts an additional 24 psi (165 kPa) to the fluid. The
production fluid is discharged to the ESP at approximately 48 psi
(331 kPa) or greater and within the pressure requirements for the
ESP intake.
[0034] Positioned above and below each stage are shaft support
assemblies 78a-d. In use, the shaft support assemblies support the
shaft 80, preventing axial bending of the shaft. The shaft support
assemblies 78a and 78d are positioned, respectively, in the base 70
and head 72, while the shaft support assemblies 78b-c are
positioned in the compression tubular 76. Alternate arrangements
are possible as will be understood by those of skill in the art.
For purposes of discussion, shaft support assembly 78c is
considered in detail.
[0035] Shaft support assembly 78c has a bearing housing 110c with a
support sleeve 112c and bushing 114c positioned therein. The
bearing housing 110c is mounted within a support compression
tubular 116c. The support compression tubular 116c forms part of
the compression tubular 76. The design shown provides ease of
assembly, however, other arrangements will be readily apparent to
those of skill in the art. For example, the compression blades,
support assemblies, etc., can be internally mounted into a single
compression tubular. In a preferred embodiment, the support
assembly, or portions thereof, is made of corrosion-resistant
materials. For example, the support tubular 116 is preferably of a
corrosion-resistant nickel alloy and the sleeve 112 and bushing 114
are of tungsten carbide. Alternate corrosion and erosion-resistant
materials and methods will be readily apparent to those of skill in
the art.
[0036] The compressor assembly, or charger, is designed for use
with production tubing and mounted below one or more ESPs, although
additional uses will be apparent to those of skill in the art.
Preferably the compressor includes more than one stage, with each
successive stage incrementally increasing the fluid pressure to a
desired pressure range corresponding to the intake specifications
of the ESP into which the fluid is discharged. Production fluid
enters the wellbore annulus and, typically after flowing through
screens or filters, into an interior passageway or bore in the
production string. The fluid flows towards the surface, through a
series of downhole tools. For example, in an exemplary production
string, the production fluid flows through a sensor assembly, a
motor assembly, one or more seal subs, one or more protectors, one
or more gas separators, a gas charger of one or more stages as
disclosed herein, and one or more ESPs, and thence to the surface.
Preferably the motor powers, by a drive shaft connected to tool
assembly shafts, the plurality of powered tools, including the gas
separator, gas charger, and ESP, for example. The motor receives
electrical power from the surface via cable in a preferred
embodiment.
[0037] The compressor can be used at any well depth, typically
ranging from 500 feet to over 13,000 feet deep. The gas charger is
expected to be most effective in wells producing production fluid
at or below 1250 barrels per day, and down to as little as 150 bpd.
It is also anticipated that the compressor will be of greater use
in wells producing larger volumes of free gas, where the compressor
will entrain or dissolve the free gas into the production liquid.
The compressor can vary in size. In a preferred embodiment, a
compressor tool is approximately four inches in diameter and
approximately 36 inches in length per section. Overall length,
obviously, is dependent on the number of stages employed. The
compressor design also reduces the likelihood of plugging due to
debris in the production fluid. The helical design of the
compressor blade 100 provides a greater flow area than alternative
compressors having impellers and diffusers.
[0038] Among the preferred embodiments, various methods or
processes are disclosed and addressed as steps. The steps are not
exclusive and can be combined in various ways, with steps omitted,
added, re-ordered, and/or repeated, as will be recognized by those
of skill in the art. The methods are limited only by the claims as
construed by applicable law. The following methods are numbered for
ease of reference and are exemplary in nature. 1. A method of
producing fluid from a subterranean well having a wellbore
extending through a hydrocarbon-bearing formation, the method
comprising the steps of: positioning at a downhole location in the
wellbore a work string having an electric motor, a compressor
assembly, and an Electric Submersible Pump (ESP); operating the
compressor assembly and the ESP using the electric motor; pumping
production fluid from the formation and into an interior passageway
of the work string, the production fluid having both free gas and
production liquid therein; compressing the production fluid using
the compressor assembly, and entraining or dissolving at least a
portion of the free gas into the production liquid; and feeding the
compressed production fluid to an intake of the ESP. 2. The method
of claim 1, wherein the step of compressing further comprises
compressing the production fluid to an intake pressure within the
operating range of the ESP intake. 3. The method of claims 1-2,
wherein the step of compressing further comprises compressing the
production fluid by between about 8 psi (55 kPa) and 60 psi (414
kPa). 4. The method of claims 1-3, wherein the step of compressing
further comprises compressing the production fluid to a pressure
above the free gas bubble point at the downhole location. 5. The
method of claims 1-4, wherein the step of compressing further
comprises compressing the production fluid in multiple stages in
the compressor assembly, and wherein each of the multiple stages
compresses the production fluid by between about 8 psi (55 kPa) and
32 psi (221 kPa). 6. The method of claims 1-5, wherein the
compressor assembly is positioned in the string between the
electric motor and the ESP. 7. The method of claims 1-6, further
comprising the step of pumping the compressed production fluid to
the surface. 8. The method of claims 1-7, wherein the compressor
assembly includes a rotary compressor element attached to a
compressor drive shaft, and further comprising the step of driving
the rotary compressor drive shaft by a drive shaft of the electric
motor. 9. The method of claims 1-8, further comprising the step of
separating at least some free gas from the production fluid using a
gas separator tool prior to the step of compressing the production
fluid using the compressor assembly. 10. The method of claims 1-9,
wherein the compressor assembly allows fluid flow therethrough
without fluid flow restriction. 11. The method of claims 1-10,
wherein the step of compressing further comprises the step of
supporting a drive shaft of the compressor assembly with at least
one bearing. 12. The method of claim 11, wherein the at least one
bearing comprises a corrosion-resistant bushing.
[0039] Persons of skill in the art will recognize various
combinations and orders of the above described steps and details of
the methods presented herein. While this invention has been
described with reference to illustrative embodiments, this
description is not intended to be construed in a limiting sense.
Various modifications and combinations of the illustrative
embodiments as well as other embodiments of the invention, will be
apparent to persons skilled in the art upon reference to the
description. It is, therefore, intended that the appended claims
encompass any such modifications or embodiments.
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