U.S. patent application number 14/912149 was filed with the patent office on 2016-07-14 for downhole gas compression separator assembly.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Jim D. Hardee, Kenneth W. Parks.
Application Number | 20160201444 14/912149 |
Document ID | / |
Family ID | 52689193 |
Filed Date | 2016-07-14 |
United States Patent
Application |
20160201444 |
Kind Code |
A1 |
Hardee; Jim D. ; et
al. |
July 14, 2016 |
DOWNHOLE GAS COMPRESSION SEPARATOR ASSEMBLY
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 intake pressure below the
operating parameters of the ESP. A gas compression separator
assembly, having a series of compressors and separation chambers,
entrains or dissolves the free gas component of the production
fluid and separates free gas for downhole disposal. The production
fluid fed to the ESP intake has an increased fluid pressure, a
reduced volumetric fluid flow, and a lower free gas content, and is
less likely to induce gas lock of the ESP.
Inventors: |
Hardee; Jim D.; (Moore,
OK) ; Parks; Kenneth W.; (Perkins, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
52689193 |
Appl. No.: |
14/912149 |
Filed: |
September 19, 2013 |
PCT Filed: |
September 19, 2013 |
PCT NO: |
PCT/US2013/060649 |
371 Date: |
February 15, 2016 |
Current U.S.
Class: |
166/265 ;
166/105.5 |
Current CPC
Class: |
E21B 43/38 20130101;
E21B 43/128 20130101 |
International
Class: |
E21B 43/38 20060101
E21B043/38; E21B 43/12 20060101 E21B043/12 |
Claims
1. A method to produce fluid from a subterranean well having a
production string positioned downhole in a wellbore extending
through a formation, the method comprising the steps of: (a)
flowing production fluid from the formation through an interior
passageway defined in the production string, the production fluid
having a free gas component and a liquid component; (b) allowing
uninterrupted production fluid flow through a gas compression
separator assembly positioned along the production string while:
compressing the production fluid in the production string;
separating at least some free gas from the production liquid; and
(c) flowing the compressed production fluid to the intake of an
ESP.
2. The method of claim 1, wherein step (b) further comprises
dissolving or entraining at least a portion of the free gas into
the production liquid.
3. The method of claim 1, wherein step (b) further comprises
venting the separated free gas to the exterior of the production
string at a downhole location.
4. The method of claim 1, wherein the step of compressing further
comprises incrementally compressing the production fluid using a
series of compressor assemblies.
5. The method of claim 4, further comprising the step of
sequentially reducing the volumetric fluid flow rate of the
production fluid using the series of compressor assemblies.
6. The method of claim 4, wherein each compressor assembly of the
series has an operating range, and further comprising compressing
the production fluid using a compressor assembly to within the
operating range of a subsequent compressor assembly.
7. The method of claim 4, wherein the compressor assemblies have at
least one impeller and at least one diffuser.
8. The method of claim 4, wherein at least one of the compressor
assemblies of the series are assembled in compression.
9. The method of claim 4, wherein the series of compressor
assemblies are divided into a plurality compression stages, each
compression stage having at least two compressor assemblies, and
further comprising driving at least two compression stages
utilizing different diameter shafts.
10. The method of claim 1, wherein the step of compressing further
includes reducing volumetric flow rate of the production fluid.
11. The method of claim 1, wherein the step of compressing further
includes increasing production fluid pressure.
12. The method of claim 1, wherein the step of separating free gas
from production liquid further comprises creating a vortex of
production fluid in a fluid chamber.
13. The method of claim 12, further comprising forcing lighter
production free gas toward the center of the vortex and heavier
production liquid toward the fluid chamber wall.
14. The method of claim 1, further comprising venting a portion of
free gas through a cross-over tool.
15. The method of claim 12, wherein creating the vortex includes
the step of rotating at least one paddle in the fluid chamber.
16. The method of claim 1, further comprising the step of pumping
the compressed production fluid to the surface using the ESP.
17. The method of claim 1, further comprising the step of reducing
the likelihood of gas lock occurring in the ESP.
18. An apparatus to prepare production fluid, having a free gas and
a liquid component, to be pumped to the surface from a wellbore
extending through a subterranean formation, the apparatus
comprising: (a) a gas compression separator assembly having a
plurality of compression stages arranged in series and at least one
gas separator assembly, the assemblies allowing uninterrupted
production fluid flow therethrough; (b) each compression stage
having at least one compressor assembly having an impeller and at
least one diffuser; and (c) each separator assembly having at least
one vent allowing flow of separated free gas to the exterior of the
apparatus.
19. The apparatus of claim 18, wherein at least one gas separator
assembly is interposed between successive compression stages.
20. The apparatus of claim 18, wherein at least one of the
compressor assemblies is mounted in compression on a rotary
shaft.
21. The apparatus of claim 20, wherein the compressor assembly
mounted in compression transmits torque through the shaft to at
least one thrust bearing.
22. The apparatus of claim 20, wherein the compressor assembly
mounted in compression includes an impeller mounted to prevent
axial movement along the shaft.
23. The apparatus of claim 18, wherein the separator assemblies
include a vortex inducer and wherein the at least one vent extends
from proximate the axis of a produced vortex to the exterior of the
apparatus.
24. The apparatus of claim 18, wherein the compressor assemblies
include an impeller made of a corrosion-resistant material.
25. The apparatus of claim 18, wherein the plurality of compression
stages comprises at least a first, second, and third compression
stage, arranged in series with at least one separator assembly
positioned between two compression stages.
26. The apparatus of claim 25, wherein the first compression stage
has at least one compressor assembly with a nominal operating range
between about 4300 and 6000 BPD.
27. The apparatus of claim 25, wherein the second compression stage
has at least one compressor assembly with a nominal operating range
of between about 3000 and 4300 BPD.
28. The apparatus of claim 25, wherein the third compression stage
has at least one compressor assembly with a nominal operating range
of between about 650 and 2200 BPD.
29. The apparatus of claim 18, further comprising at least one ESP
in fluid communication with the gas compression separator
assembly.
30. The apparatus of claim 18, further comprising an electric motor
having a drive shaft for powering the compressor assemblies and at
least one gas separator assembly.
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 reducing free gas in production fluid by
separating free gas from production liquid and by compressing the
production fluid to dissolve or entrain free gas.
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 often 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 typically
provided from a surface source by power cable extending to the
downhole electric motor. Additional tools are used in conjunction
with an ESP and electric motor, including one or multiple seal
subassemblies, protectors, sensor assemblies, gas separators,
additional pumps, standing valves, etc. The electric motor
typically is used to power the pumps, gas 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,
or free gas, interferes with operation of the pump, preventing
intake of production fluid. Natural gas, and other naturally
occurring gases, is often found entrained or dissolved in the
production fluid. Where the gas is in a gaseous phase, mixed 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.
[0005] Further, it is often undesirable to produce natural gas from
wells having both gas and oil, for example. Consequently, downhole
gas separators are used to separate the gaseous fluid from the
liquid fluid of the production fluid at a downhole location, with
the gaseous fluid vented back into the wellbore. The produced fluid
at the surface is then composed of a larger percentage of the
preferred liquid fluid. Free gas at the surface can still occur,
for example, as the production fluid reaches the bubble point
during pumping to the surface, however, a smaller amount of gaseous
phase fluid occurs with the use of downhole separators.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] 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:
[0007] FIG. 1 is a schematic view of an exemplary well system
utilizing an embodiment of a gas compression separator assembly
disclosed herein;
[0008] FIG. 2 is a schematic partial view of an exemplary tubing
string having various downhole tools thereon, including an
electrical submersible pump and electrical motor for use in
conjunction with a gas compression separator assembly according to
the disclosure;
[0009] FIGS. 3A-B are cross-sectional views of a lower section of
an exemplary gas compression separator assembly according to an
aspect of the disclosure;
[0010] FIGS. 4A-B are cross-sectional views of an upper section of
the gas compression separator assembly according to an aspect of
the disclosure; and
[0011] FIGS. 5A-B are cross-sectional views of another exemplary
embodiment of a gas compression separator according to an aspect of
the disclosure.
[0012] 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
[0013] 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.
[0014] 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.
[0015] 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.
[0016] FIG. 1 is a schematic illustration of a well system,
indicated generally 10, having a compressor and gas separator
assembly according to an embodiment of the disclosure. A wellbore
12 extends through various earth strata, including at least one
production zone. 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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, including gas
compression separator assembly 42.
[0021] FIG. 2 is a schematic view in elevation of an exemplary
tubing string having various downhole tools thereon, including an
electrical submersible pump and electric motor for use in
conjunction with a compressor and gas separator assembly according
to the disclosure.
[0022] The tubing string 30 includes multiple connected downhole
tools 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 compression separator assembly 42a-b,
and an electrical submersible pump assembly 46. The gas compression
separator assembly 42 is divided into a lower section 42a and an
upper section 42b. The protector 40 is seen in partial tear-away to
show an exemplary thrust bearing assembly 150. The thrust bearing
is discussed in greater detail below herein. 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 combined tubing and production strings can be referred to as a
production string for ease of reference. The ESP assembly pumps the
production fluid to the surface via tubulars 32.
[0023] FIGS. 3A-B and 4A-B are cross-sectional views of an
exemplary gas compression separator assembly 42 according to an
aspect of the disclosure. FIGS. 3A-B provide a cross-sectional view
of the lower section 42a of the gas compression separator assembly
42, and FIGS. 4A-B provide a cross-sectional view of the upper
section 42b of the gas compression separator assembly 42. The
Figures are discussed in sequence, however, like parts on the
sections are indicated by like numbers, typically with a
distinguishing suffix.
[0024] The gas compression separator 42 is designed to treat, at a
downhole location, production fluid having both a free gas
component and a liquid component. Generally, the exemplary gas
separator assembly 42 is seen split into a lower section 42a and
upper section 42b. The division into sections is largely for ease
of manufacture, assembly, and transport. As shown, the lower
section 42a includes a first compression stage 50a and a second
compressor stage 50b, arranged in series, with each stage having
two impellers and diffusers. Similarly, the upper section 42b has a
third compressor stage 50c and a fourth compressor stage 50d, also
in series, and each having two impellers and diffusers. Each
compressor stage acts on the production fluid to incrementally
increase fluid pressure (typically measured in psi), decrease fluid
volume, and reduce volumetric fluid flow rate (often measured in
barrels per day, bpd). The stage capacities are carefully selected
such that, at each stage, the production fluid is within the
operating pressure range and flow rate range for that compressor
stage. Similarly, each compressor stage provides compressed
production fluid to the next compressor stage in the series at a
pressure and flow rate within the operating range of the next
stage.
[0025] Generally, the compression stages receive production fluid
and, via centrifugal forces, compress it to reduce free gas in the
fluid. The compression stages raise fluid pressure prior to
discharge. The centrifugal force entrains free gas into a
gas-liquid mix and dissolves gas into the production liquid. The
compressor is preferably powered by the electric motor via a drive
shaft although alternative power sources can be applied. Production
fluid entering the compressor proceeds through multiple compression
stages, with fluid pressure increased at each stage. Stages are
arranged in series to produce, for each stage and for a combined
total, a target fluid pressure, a target production volume (e.g.,
in bpd), a target flow rate, etc.
[0026] 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,
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. The compression stages
herein better handle debris, eliminate high-erosion points, reduce
likelihood of erosive failure, and prolong useful life of the tool.
The compressor design does not restrict or limit fluid flow, or
hydrocarbon production, to increase fluid pressure.
[0027] The system relies on a series of multiple compression
stages, but the number, size, and capacity of stages is selected
based on the application, formation pressure, formation depth,
production rate, free gas to liquid mix, etc. Consequently,
alternative embodiments can employ fewer or greater compression
stages, with varying stage specifications, and fewer or more
compression stages per section. The number of compression stages,
impellers, diffusers, staging sections, and the specifications for
each, provided herein are therefore exemplary and not limiting.
[0028] Turning to FIG. 3A-B, the lower section 42a is seen having
compressors arranged as stages 50a-b, a fluid chamber 52a, a base
assembly 54a, a head assembly 56a, and a gas separation assembly
58a. A generally cylindrical housing 60a encloses the compression
stages 50a-b, fluid chamber 52a, separation assembly 58a, and
portions of the base 54a and head 56a assemblies. Further, a
compression tube 61 is formed along much of the length of the tool
section, with compression tube sections 61a-b combining with
diffuser bodies 118a-d, and compressor bases 116a-b to form the
compression tube. The section elements define an interior
passageway 63 extending the length of the section 42a, through
which production fluid flows.
[0029] Drive shaft 62a extends longitudinally through the assembly
42a, having a keyway 64a for attachment of rotary elements to the
shaft, upper and lower spline sections 66 for connecting the shaft
to similar shafts above and below the tool. The shaft is powered,
typically, by an electric motor having a rotary drive shaft and
positioned downhole from the gas compression separator assembly
42a. An exemplary shaft, for example, has an 11/16 inch (1.746 cm)
diameter and is made of a high strength metal such as Inconel 718
(trade name). A preferable shaft design is rated for a maximum of
500 horsepower. 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 shaft components.
[0030] The shaft is supported radially by a plurality of bearing
assemblies 68a-e spaced along the shaft length. Bearing assemblies
are known in the art and can preferably include associated sleeves,
bushings, snap rings, pins, screws, or other attachment mechanisms.
The bearings provide stability to the drive shaft during rotation.
More or fewer bearings can be used depending on construction,
materials, expected operating conditions, etc. Preferably the
bearings are made of hardened materials, such as tungsten for
example.
[0031] Base bearing 68a has a tubular body 70, bearing sleeve 72,
and bushing 74. Preferably sleeves 76a-e oppose the bearings 68a-e
or associated bushings, respectively. The sleeves 76 are preferably
hardened, such as of hardened carbide, etc., as is known in the
art. Spacing and attachment mechanisms, such as two-piece ring 78a,
spacer 80, shims, etc., can be used as those of skill in the art
will recognize. Additional bearings can be of alternate
construction, or provided in whole or in part by another tool
element, such as the impeller, diffuser and cross-over assemblies,
for example.
[0032] Base assembly 54a has a base body 82a threadedly or
otherwise attached to the section housing 60a. The base defines an
interior passageway 63a which forms a portion of passageway 63. The
base has a fluid intake 84a for receiving fluid from a tool or
tubing positioned below and a fluid outlet 86a for delivering fluid
to a tool or tubing positioned above. In this instance, the outlet
delivers fluid to the upper section 42b. The base 82a houses
bearing 68a and the lower end of the shaft 62a, and has a coupling
88a for attachment to an adjacent tool or tubing.
[0033] The head assembly 56a is of similar construction, having a
head body 90a defining an interior passageway 63f which forms a
portion of passageway 63. The head houses bearing 68e, sleeve 76e,
and the upper end of the shaft 62a, and provides a tool coupling
92a. The head also defines a fishing neck 94a, as is known in the
art. The head assembly 56a is a cross-over tool, providing for
fluid, in this case separated free gas, to cross from the interior
chamber 140a to the exterior of the lower tool 42a. Most or all of
the separated free gas is vented, through a plurality of vents 96a,
preferably to the wellbore or casing annulus defined between the
tool section 42a and the wellbore or casing. The production liquid
(and any remaining gas) flows through a plurality of interior ports
98a defined in the head body 90a and thence through head outlet
100a. The head assembly is threadedly or otherwise attached to the
section housing 60a and by lock plate 102a.
[0034] Fluid chamber 52a is defined between the first and second
compression stages 50a and 50b and interior to compression tube
61a. Shaft 62a extends through the fluid chamber. The chamber
receives compressed fluid from the outlet of the first compressor
assembly 50a and delivers fluid to the inlet of second compressor
assembly 50b. Fluid pressure, fluid volume, and fluid flow rate are
static across the fluid chamber 52a.
[0035] The lower section 42a is seen having a plurality of
compressor assemblies, namely, 50a-b. Similarly, the upper section
42b has a plurality of compressor assemblies 50c-e. The first
compressor assembly 50a is discussed in detail, with the remaining
compressor assemblies 50b-e only briefly described as they have
many of the same features and construction. Compressor assemblies
are generally known in the field, as those of skill in the art will
recognize. Exemplary first compressor assembly 50a is comprised of,
in order of fluid flow, impeller assembly 104a, diffuser assembly
106a, impeller assembly 104b, and diffuser assembly 106b.
[0036] Impeller assembly 104a is discussed in detail, the
description applying to the remaining impeller assemblies where
like parts have like numbers with distinguishing suffixes in the
figures. Impeller assembly 104a has an impeller body 108a, a hub
110a which attaches to the shaft 62a, and defines a plurality of
radially and longitudinally extending impeller passageways 112a
which are separated by a plurality of vanes. Impeller inlet 113a
intakes fluid from the base outlet 86a. Impeller outlets 114a emit
production fluid to diffuser inlets 123a. A compressor base 116a
provides for mounting and stability of the impeller and diffuser
assemblies. The remaining impeller assemblies 104b-d of the lower
section 42a are of similar construction and function. Impeller
outlets 114b of impeller assembly 104c emit fluid into the fluid
chamber 52a. Preferably the impellers and diffusers are made of
corrosion-resistant material, such as tungsten alloy, nickel alloy,
Ni-Resist, 9-chrome 1-molly, and the like, as are known in the art.
Impeller design and use is known in the art to those of ordinary
skill and will not be discussed in greater detail herein.
[0037] Diffuser assembly 106a is discussed in detail, the
description applying to the remaining diffuser assemblies where
like parts have like numbers with distinguishing suffixes. Diffuser
assembly 106a has a diffuser body 118a, a hub 120a which also
provides a bearing surface for the shaft 62a or the sleeve 76b, and
defines a plurality of radially and longitudinally extending
diffuser passageways 122a which are separated by a plurality of
vanes. Diffuser outlet 124a emits production fluid to the inlet
113b of impeller 104b. The diffuser inlets 123a accept fluid from
the outlets 114a of the impeller 104a. Preferably the diffusers are
made of corrosion-resistant materials, such as tungsten alloy,
carbide, nickel alloy, and the like. Diffuser design and use is
known in the art to those of ordinary skill and will not be
discussed in greater detail herein.
[0038] A compression nut assembly 130a is mounted to the shaft 62a
above the compressor assembly 50b. The exemplary compression nut
assembly has a compression nut 132a, compression sleeve 134a, set
screw 136a, and two-piece ring 138a. The compression nut assembly
acts as a mounting or retainer for the compressor and bearing
elements below the compression nut assembly. In a preferred
embodiment, the compression nut assembly is fixedly attached to the
shaft and provides a load-bearing face for mounting the below
elements in compression. The compression nut assembly and two-piece
ring 78b work to "sandwich" the intervening elements, maintaining
them in compression. Compression nut assemblies and equivalents are
known in the art. Further, a deflector or protective sleeve can be
used to protect the compression nut assembly from direct
impingement by sand-laden production fluid.
[0039] The gas separation assembly 58a includes a plurality of
vortex generators 142a mounted to the shaft 62a and positioned in a
gas separation chamber 140a. A pair of vortex generators is mounted
to the shaft 62a to rotate with the shaft. The vortex generators
have radially extending, vertical paddles 144a on a hub 146a
supported by the shaft 62a. The paddles stir passing production
fluid in the chamber 140a, creating a vortex, wherein the heavier
liquid components are forced radially outward against the chamber
wall 148a while free gas components gather near the vortex axis
near the center of the chamber. The length of the chamber 140a is
selected to provide sufficient dwell time to allow for adequate
separation of free gas and liquids. The length of the chamber can,
in part, be determined by the formation and production
characteristics, such as the amount of produced gas and production
pressure. Free gas is separated from the production liquid
component and exits the chamber and the tool section through the
cross-over head vents 96a. The remaining production fluid is drawn
through interior ports 98 and continues upward through the
assembly. Other vortex generators are known in the art and can be
used alone or in combination with the generators 142a shown.
[0040] Turning to FIG. 4A-B, the upper section 42b is seen having
compressors arranged as stages 50c-e, a fluid chamber 52b, a base
assembly 54b, a head assembly 56b, and a gas separation assembly
58b. A generally cylindrical housing 60b encloses the compression
stages 50c-e, fluid chamber 52b, separation assembly 58b, and
portions of the base 54b and head 56b assemblies. Further, a
compression tube 61 is formed along much of the length of the tool
section, with compression tube sections 61c-d combining with
diffuser bodies 118e-i, compressor bases 116c-d, and diffuser
bearing housings 119a-b, to form the compression tube. The section
elements, as those of the lower section, continue to define
interior passageway 63 extending the length of the section 42a, for
production fluid flow.
[0041] Drive shaft 62b extends longitudinally through the assembly
42b, having a keyway 64b for attachment of rotary elements to the
shaft, upper and lower spline sections 66 for connecting the shaft
to similar shafts above and below the tool. The shaft is powered,
typically, by an electric motor having a rotary drive shaft and
positioned downhole from the gas compression separator assembly
42b. An exemplary shaft, for example, has an 11/16 inch (1.746 cm)
diameter and is made of a high strength metal such as Inconel 718
(trade name). A preferable shaft design is rated for a maximum of
200 horsepower (202.8 hp(M)). 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.
[0042] The shaft is supported radially by a plurality of bearing
assemblies 68f-k spaced along the shaft length. Bearing assemblies
are known in the art and can preferably include associated sleeves,
bushings, snap rings, pins, screws, or other attachment mechanisms.
The bearings provide stability to the drive shaft during rotation.
More or fewer bearings can be used depending on construction,
materials, expected operating conditions, etc.
[0043] Base bearing 68f is of similar construction to base bearing
68a described above herein and will not be discussed in detail.
Preferably treated sleeves 76f-k oppose bearings 68f-k or their
bushings, respectively. The sleeves are preferably made of hardened
material, such as iron carbide, etc. Spacing, stabilizing, and
attachment mechanisms, such as two-piece ring 78b, spacers 80,
shims, etc., can be used as those of skill in the art will
recognize. Additional bearings can be of alternate construction, or
provided in whole or in part by other tool elements, such as a
diffuser body, diffuser bearing housing, cross-over body, etc.
[0044] Base assembly 54b has a base body 82b threadedly or
otherwise attached to the section housing 60b. The base defines an
interior passageway 63g which forms a portion of passageway 63. The
base has a fluid intake 84b for receiving fluid from a tool or
tubing positioned below and a fluid outlet 86b for delivering fluid
to a tool or tubing positioned above. In this instance, the outlet
86b delivers fluid to the inlet of compressor assembly 104e. The
base 82b houses bearing 68f and the lower end of the shaft 62b, and
has a coupling 88b for attachment to an adjacent tool or
tubing.
[0045] The head assembly 56b is of similar construction, having a
head body 90b defining an interior passageway 63n which forms a
portion of passageway 63. The head houses bearing 68n, sleeve 76n,
and the upper end of the shaft 62b, and provides a tool coupling
92b. The head also defines a fishing neck 94b, as is known in the
art. The head assembly 56b is a cross-over tool, providing for
fluid, in this case separated free gas, to cross from the interior
chamber 140b to the exterior of the lower tool 42b. Most or all of
the separated free gas is vented, through a plurality of vents 96b,
preferably to the wellbore or casing annulus defined between the
tool section 42a and the wellbore or casing. The production liquid
(and any remaining gas) flows through a plurality of interior ports
98b defined in the head body 90b and thence through head outlet
100b. The head assembly is threadedly or otherwise attached to the
section housing 60b and by lock plate 102b.
[0046] Fluid chamber 52b is defined between the compression stages
50c and 50d and interior to compression tube 61b. Shaft 62b extends
through the fluid chamber. The chamber receives compressed fluid
from the outlet of the compressor assembly 50c and delivers fluid
to the inlet of compressor assembly 50d. Fluid pressure, fluid
volume, and fluid flow rate are static across the fluid chamber
52b.
[0047] The upper section 42b is seen having a plurality of
compressor assemblies, namely, 50c-d, similar in construction to
those of the lower section 42a. Since the compressor assembly 50a
is discussed in detail above, the compressor assemblies 50c-d are
only briefly described. Compressor assemblies are generally known
in the field, as those of skill in the art will recognize
Compressor assembly 50c is comprised of, in order of fluid flow,
impeller assembly 104e, diffuser assembly 106e, impeller assembly
104f, and diffuser assembly 106f. The assembly further preferably
includes a diffuser bearing 121a having a housing 119a and fluid
passageways 123a. The diffuser bearing 121a provides additional
stability for the shaft 62b at bearing assembly 68i and sleeve 76i,
similar to those described above herein. Similarly, the compressor
assembly 50e also includes, at its upper end, a diffuser bearing
121b having a housing 119b and defining fluid passageways 123b. The
diffuser bearing 121b provides additional stability for the shaft
62b at bearing assembly 68m and sleeve 76m, similar to those
described above herein.
[0048] Impeller and diffuser assemblies 104 and 106 are discussed
in detail above, with the description applying to the remaining
impeller and diffuser assemblies, where like parts have like
numbers with distinguishing suffixes. Impeller assemblies 104e-j
and diffuser assemblies 106e-j are of similar construction and will
not be discussed in further detail.
[0049] A compression nut assembly 130b is mounted to the shaft 62b
above the compressor assembly 50d. The exemplary compression nut
assembly has a compression nut 132b, compression sleeve 134b, set
screw 136b, and two-piece ring 138b. The compression nut assembly
is fixedly attached to the shaft and provides a load-bearing face
for maintaining the elements below in compression between the
compression nut assembly and two-piece ring 78b.
[0050] The gas separation assembly 58b includes a plurality of
vortex generators 142b mounted to the shaft 62b and positioned in a
gas separation chamber 140b. A pair of vortex generators is mounted
to the shaft 62b to rotate with the shaft. The vortex generators
have radially extending, vertical paddles 144b on a hub 146b
supported by the shaft 62b. The paddles stir passing production
fluid in the chamber 140b, creating a vortex, wherein the heavier
liquid components are forced radially outward against the chamber
wall 148b while free gas components gather near the vortex axis
near the center of the chamber. Free gas is separated from the
production liquid component and exits the chamber and the tool
section through the cross-over head vents 96b. The remaining
production fluid is drawn through interior ports 98b and continues
upward through the assembly.
[0051] Generally, the assembly can be implemented either in
compression or as a "floater" design in accordance with various
embodiments of the present disclosure. Preferably, the assemblies
are assembled in compression. In the lower section 42a, seen in
FIG. 3A-B, the compression nut assembly 130a, at the upper end, and
the two-piece split ring 78a, at the lower end, serve to place into
compression each of the impeller hubs 110a-d, sleeves 76b-d, and
spacers. From the compression nut assembly 130a to the two-piece
split ring 78a, a continuous series of metal parts in
metal-to-metal contact is provided. Similarly, in the upper section
42b seen in FIG. 4A-B, the compression nut assembly 130b, at the
upper end, and the two-piece split ring 78b, at the lower end,
serve to place into compression each of the impeller hubs 110e-h,
sleeves 76g-k, and spacers 80. From the compression nut assembly
130b to the two-piece split ring 78b, a continuous series of metal
parts with metal-to-metal contact is provided. Similarly, in FIG.
5A-B, compression nut assembly 330 and two-piece ring 278 act to
maintain the intervening part in compression.
[0052] During assembly of the gas compression separator assembly,
the compression nut assembly is used to place substantial force
(e.g., 50-60 ft-lbs) on the metal part stack (impellers, sleeves,
spacers) to pull the parts into contact with one another and to
place them in compression.
[0053] A schematic view of a simplified, exemplary thrust bearing
assembly 150 is seen in FIG. 2. To set the configuration in
compression, a thrust bearing is provided to bear the thrust of the
rotating portions of the sections. The thrust bearing can be
positioned at the lower end of the lower section 42a, or elsewhere
along the drive shaft. In the exemplary embodiment, the thrust
bearing assembly 150 is positioned at the lower end of the
protector 40. The thrust bearing assembly 150 includes a thrust
bearing 152, a two-piece split ring 154, and spacer 156, positioned
about protector shaft 158. The thrust bearing 150 is supported by a
support block 160 which is an extension of or attached to the
protector housing, for example.
[0054] In practice, during assembly, the shaft of the gas
compression separator assembly is lifted a small amount (e.g., 0.15
to 0.030 inches), such that the impellers are not supported by the
diffusers. The weight of the impellers, sleeves, and shaft are then
supported by the thrust bearing below. This prevents premature wear
to the impellers and diffusers due to down-thrust because the
impellers do not touch, or do not place weight upon, the diffusers
or diffuser thrust pads Shims are used during assembly at the
bottom end of the shaft to position the shaft correctly, supported
by the shaft of a below protector or other tool, such that the
proper spacing is provided between the impellers and diffusers and
the impeller and shaft weight and down-thrust is borne by the
thrust bearing rather than the diffusers. An exemplary shim raises
bottom of the shaft in the range of about 0.015 to 0.030 inch.
[0055] Returning briefly to FIG. 2, 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.
[0056] The electric motor assembly 36 includes a housing 48 and an
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.
[0057] 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.
[0058] 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.
[0059] In use, production fluid which enters the production string,
typically through screen assemblies 24 positioned in the wellbore
downhole from the electric motor assembly 36. The production fluid
is pulled upwards in response to the operation of the one or more
ESPs. Production fluid flows past the electric motor 50 at assembly
36, through the one or more seal subs 38 and protectors 40, through
the gas compression separator 42a-b, and to the intake of ESP 46.
Fluid is pumped to the surface through tubing 32. The operation and
methods of the seal subs, protectors, ESP, electric motor, and
sensors are known in the art and not described in detail here.
Additional tools can be employed on the production string as
well.
[0060] The electric motor 50, powered by an electric cable 54 from
the surface, rotates a drive shaft 52. The drive shaft 52 is
connected to and powers the shafts of the gas compression separator
42 and the ESP 46. The shaft is radially supported at various
locations including in the gas compression separator at bearing
assemblies 68a-e.
[0061] Turning to the gas compression separator, production fluid
having liquid and gaseous components enters the gas compression
separator lower section 42a at base assembly intake 84. In lower
section 42a and upper section 42b, the production fluid flows
through a series of compression stages 50a-b and 50c-e,
respectively, although a fewer or a greater number of stages can be
employed. Each compression stage takes in a relatively large
volumetric flow rate of production fluid and reduces, by
compression, the volumetric flow rate. Each stage builds
compression, increases fluid pressure, and reduces volumetric flow
rate. As fluid pressure increases, free gas in the production fluid
is dissolved or entrained into the production liquid. The division
of the stages into upper and lower sections allows, among other
things, for use of different shaft sizes. In one example, a larger
7/8 inch diameter shaft is used in the lower section to rotate
relatively larger compression stages, while a smaller 11/16 inch
diameter shaft is used in the upper section to rotate relatively
smaller compression stages.
[0062] The stages each preferably include two compressor assemblies
which, in turn, have two impeller assemblies and two diffuser
assemblies. The impellers are attached to the shaft and rotate as
the shaft rotates. In a preferred embodiment, the electric motor
rotates the impellers in the range of about 3000-5000 rpm, and more
specifically between about 3500-4500 rpm. Preferably, at least the
lower section is assembled in compression, eliminating stage damage
from running out of the acceptable operating range of a comparable
floater assembly. A thrust bearing carries the thrust forces and
can be positioned at the lower end of the lower section 42a or in a
lower tool assembly, such as the protector. Also preferably, at
least some of the compression stages or compressor assemblies in
the upper section 42b are configured in compression. With the
assemblies, or portions thereof, in compression and weight and
thrust carried by the thrust bearing, the system has a greater
usable operation range. A floater configuration is designed for use
without damage in an optimum range, for example, between 2500-3500
BPD. A similar system configured in compression can operate in a
wider range, for example, between 1000-4000 BPD without mechanical
damage to the impellers or diffusers.
[0063] The stage capacities are selected to gradually reduce the
volumetric fluid flow and correspondingly gradually increase the
fluid pressure. In an exemplary embodiment of the disclosure, the
first compressor stage 50a utilizes two nominal 4300 BPD (normal
range 3000-5400 BPD) compressor assemblies arranged in series. At
the second stage 50b, two nominal 3000 BPD (normal range 2000-3600
BPD) compressor assemblies are utilized in series. The third stage
50c, in the upper section, utilizes two compressors capable of
about 2200 BPD, in an exemplary embodiment. The fourth stage 50d
utilizes two compressor assemblies with a capacity of about 1750
BPD, and the fifth stage utilizes compressor assemblies of about
850 BPD.
[0064] Other arrangements can be used. In further exemplary
embodiments, the following stage capacities and characteristics can
be used as seen in Chart 1 in which figures are in barrels per day
(BPD) and represent the capacities of the compressor assemblies in
each exemplary stage in order of fluid flow.
TABLE-US-00001 CHART 1 Stage 1 2 3 4 5 Example 1 6000/6000
4300/4300 2200/2200 2200/2200 1750/1750 Example 2 4300/4300
3000/3000 1750/1750 1250/1250 1250/1250 Example 3 4300/4300
3000/3000 850/650 850/650 850/650
[0065] Compressor capacities are listed as nominal values but are
designed to safely operate within an operational flow rate range.
Flow rate maximums and minimums are known for a given compressor
assembly. For example, a compressor assembly listed at 650 BPD has
an operational range of 415 to 867 BPD. In this example, the lower
end of the standard operational range (415 BPD) is approximately 36
percent below the nominal flow rate (650 BPD). The operating
ranges, however, are provided on the assumption that the compressor
assemblies are mounted in floater configuration on the drive shaft.
Compressors in floater configuration are not as tolerant of rate
variations or extreme operational ranges as compressors assembled
in compression. In the preferred embodiment, however, at least one
stage of compressor assemblies are mounted in compression as
explained elsewhere herein. This allows the compressor assemblies
configured in compression, as in the preferred embodiment, to run
in a much expanded operational range. When a 650 BPD compressor
assembly is mounted in compression, for example, its lower end
operational range is extended to around about 200 BPD. (Caution
should be taken at these lower rates to insure adequate flow for
cooling of the electric motor.) The lower end (200 BPD) of the
modified operational range, in this example, is approximately 69
percent below the nominal flow rate (650 BPD).
[0066] Production fluid compressed in the first two stages flows
into the chamber 140a and is stirred into a vortex by the rotation
of the paddles 144a mounted to the drive shaft 62a. Centrifugal
force pushes the heavier liquid component of the production fluid
toward the compression tube wall 148a while the lighter gaseous
component of the production fluid moves towards the vortex axis
near the shaft. The free gas flows up the vortex axis and into the
vents 96a defined in the head assembly 56a. The free gas is ported
to the exterior of the lower section 42a, typically into an annulus
formed between the section and the casing or wellbore. The liquid
component, as well as any remaining free gas, flows upwards into
and through the interior ports 98a defined in the head assembly.
The production fluid passes out of the lower section through outlet
100a and into the upper section 42b.
[0067] Briefly, the compression and separation processes are
repeated in the upper section 42b. Production fluid, compressed and
with lowered gas content, from the lower section 42a is received
into inlet 84b of the base assembly 54b and passes into the third
compressor stage 50c. The impellers 104e-f compress the production
fluid resulting in higher fluid pressure, dissolving and entraining
of free gas, and a reduction in volumetric fluid flow rate.
Exemplary compressor sizes are provided above in Chart 1.
Production fluid leaving the third stage passes through fluid
passageways 123a of diffuser bearing 121a. Fluid flows through
chamber 52b and into the fourth stage 50d and its two compressor
assemblies with impellers 104g-h. Fluid exits the fourth stage into
chamber 63k and enters the fifth stage 50e, where the impellers
104i-j further compress the production fluid, reduce volumetric
flow rate, and dissolve and entrain free gas. Fluid flows through
diffuser bearing 121b and into the separation assembly 58b. The
diffuser bearings 121a-b provide stability for the shaft 62b. The
diffuser bearings do not restrict fluid flow or create an increase
in backpressure on the fluid.
[0068] Separator stage 142b works similarly to separation assembly
142a, separating free gas and liquid via vortex, with free gas
exiting the upper section 42a through vents 96b and production
liquid (and any remaining free gas) passing through ports 98b and
through outlet 100b. Mounted above the head assembly 56b is
preferably at least one ESP for pumping the compressed production
fluid to the surface.
[0069] The gas compression separator assembly can be used at
various well depths, typically ranging from 500 feet to over 13,000
feet deep. It is anticipated that the gas compression separator
assembly will be of greater use in wells producing larger volumes
of free gas, where the assembly entrains or dissolves free gas into
the production liquid. The system is useful to prevent or reduce
gas lock conditions, repetitive time-outs, restarts, down time, and
consequent lost production.
[0070] The gas compression separator assembly does not rely on flow
restriction to build pressure or to regulate fluid flow rates to
within a range determined by the ESP capacity. No restriction plate
or flow regulator plate is positioned in the system. Instead, the
gas compression separator acts to compress the production fluid
including its free gas component allowing fluid flow to continue
uninterrupted while reducing the volumetric flow rate. In the
exemplary embodiment described herein, the volumetric flow rate is
reduced by a factor of up to approximately 18. The gas compression
separator assembly allows uninterrupted production fluid flow
through the production string along the assembly length. This does
not imply that the compressor and separator assemblies do not,
respectively, compress production fluid and separate free gas from
the production fluid. Rather, the fluid flow is uninterrupted by
any back-pressure or restriction devices, such as restrictor
plates, restriction orifices, nozzles, or ports, or other flow
restriction devices (such as "diffusers" designed to restrict flow
rate, for example) which restrict or regulate fluid flow in order
to create back-pressure or limit flow to a rate within the
operating range of an ESP, etc. The uninterrupted flow is output at
the assembly outlet, preferably to an intake of an ESP positioned
above the assembly. Alternately, the production fluid, now
compressed and with a reduced free gas volume, can be flowed
through additional tools, passageways, etc., to one or more ESPs
positioned above. The ESP pumps the production fluid to the surface
and, like the compressor assemblies and separator assemblies of the
gas compression separator assembly, is powered by rotary shaft
driven by the downhole electric motor.
[0071] FIGS. 5A-B are cross-sectional views of another exemplary
embodiment of a gas compression separator according to an aspect of
the disclosure. The figures show a gas compression separator of
alternate construction but having similar elements as those
described in detail above with respect to FIGS. 3-4. Consequently,
the description regarding FIGS. 5A-B is concise, with fewer part
references and the description of parts above applying to like
parts in assembly 200. The assembly seen in FIGS. 5A-B can be used
as a substitute for the upper section 42b or as a stand-alone
unit.
[0072] The tool section 200 has a series of compressors arranged in
compression stages 250a-c, fluid chamber 252, base assembly 254,
head assembly 256, and a gas separation assembly 258, positioned in
or connected to a generally cylindrical housing 260. A compression
tube 261 is formed by a combination of compressor tubes 261a-b,
diffuser bodies 318, and diffuser bearing housings 319. An interior
passageway 263 is defined through the tool section 200 for flow of
production fluid.
[0073] Drive shaft 262 extends through the assembly 200 and has a
keyway 264 for attachment of rotary elements to the shaft. Upper
and lower splines 266 allow connection to similar shafts above and
below.
[0074] The shaft is supported by a plurality of bearing assemblies
268a-j. Bearing assemblies are known in the art and preferably
include associated sleeves, bushings, snap rings, pins, screws,
etc. Bearing assemblies can be stand-alone and fitted into the
tool, as with the bearings 268a in the base assembly 254 and
bearing 268j in the head 256, or can be part of or partially formed
by compressor elements such as, for example, diffuser bodies,
diffuser bearing housings, etc. The bearings are of similar design
and function as those described elsewhere herein and are not
described in detail.
[0075] Base assembly 254 has a body 282 attached to the housing
260, a fluid intake 284, and a fluid outlet 286. The base 282
further houses bearing 268a and has a coupling 288 for attachment
to an adjacent tool or tubing. The head assembly 256 has a body 290
defining a portion of passageway 263. The head assembly includes
bearing 268j, a tool coupling 292, and a fishing neck 294. The head
assembly is a cross-over tool, providing a plurality of vents 296
for separated free gas to cross from the chamber 340 to the
exterior of the tool section 200. Production liquid (and remaining
free gas) flows through ports 298 to a tool attached above.
[0076] Fluid chamber 252 is defined between the compression stages
250b and 250c. In a preferred embodiment, the compression nut
assembly 330 is positioned in the chamber 252.
[0077] The tool section 200 has a plurality of compression stages
250a-c. Each stage has two corresponding compressor assemblies 205
in a preferred embodiment. For example, the first compression stage
250a includes compressor assemblies 205a-b. The compressor
assemblies each comprise an impeller 304 and diffuser 306. The
diffusers 306 typically include a bearing assembly 268. As an
example, compressor assembly 205a includes impeller 304a, diffuser
306a, bearing assembly 268b, diffuser bodies 318, and a compressor
base 316. The remaining stages, compressors, etc., have similar
reference numbers and will not be called out. Compressor assemblies
are known in the art as those of skill will recognize.
[0078] In an exemplary embodiment, the compression stage 250a
utilizes two compressor assemblies with a 2200 BPD capacity, the
compression stage 250b utilizes two compressor assemblies with 1250
BPD capacity, and the compression stage 250c utilizes two
compressor assemblies with 650 BPD capacity. The compressor
assemblies in a stage can have the same or differing capacities,
more or fewer compression stages and compressor assemblies can be
used, etc.
[0079] The gas compression separator assembly preferably also
includes one or more diffuser bearings 321 each having a housing
319. The diffuser bearings 321 provide additional stability for the
shaft 262.
[0080] Impeller and diffuser assemblies are discussed in detail
above with descriptions applying to the impellers 304a-f and
diffusers 306a-f.
[0081] A compression nut assembly 330 is mounted on the shaft 262
above compressor assembly 205d. The exemplary compression nut
assembly has a compression nut, sleeve, set screw, and two-piece
ring, as described above herein, and can be used with necessary
spacers 280. The compression nut assembly acts as a mounting or
retainer for the compressor and diffuser bearing elements below. In
a preferred embodiment, the compression nut assembly attaches
fixedly to the shaft and provides a load-bearing face for mounting
the compressor assemblies and diffuser bearings in compression.
Compression nut assemblies and equivalents are known in the
art.
[0082] The gas separation assembly 258 includes a plurality of
vortex generators 342 mounted to the shaft 262 and positioned in a
chamber 340. The vortex generators are discussed above herein and
will not be described in detail here. The vortex generators create
a vortex, wherein heavier production liquid components are forced
outward against the chamber wall while the lighter free gas
component gathers near the vortex axis proximate the shaft.
Separated free gas exits the chamber and the tool section through
vents 296. The remaining production fluid is drawn through interior
ports 298.
[0083] As described above, the assembly or portions thereof can be
assembled in compression or in floater configuration. Preferably,
the gas compression separator assembly is in compression, in part
or in whole. Here, the elements below the compression nut assembly
330 and above the two-piece ring 278 are in compression. The
compression nut assembly 330 and two-piece ring 278 act to hold the
intervening impellers 304a-f, bearing sleeves, and spacers 280 in
compression. From the compression nut assembly 330 to the two-piece
split ring 278, a continuous series of metal parts, in
metal-to-metal contact, is provided. Assembly of parts in
compression is described elsewhere herein. Similarly, the use and
positioning of a thrust bearing is described elsewhere herein.
Method Claim Support
[0084] In preferred embodiments, various methods are disclosed. The
steps listed herein infra are not exclusive, not all required in
methods disclosed herein, and can be combined in various ways and
orders. It is explicitly stated that the following steps can be
arranged in different orders, omitted, repeated, transposed, and/or
re-arranged, and additional steps can be added. Steps presented in
an order XYZ, for example, can be performed in the order XZY, YXZ,
YZX, etc. Persons of ordinary skill in the art, upon reading this
disclosure, will be well aware of various methods including some or
all of the steps disclosed herein without an exhaustive listing of
every potential combination of steps, addition or omission of
steps, etc. Further, a person of ordinary skill in the art will
understand that and which steps can be performed, and in what
various orders, without those steps being listed consecutively in a
single paragraph. Steps and methods which are disclosed herein in
relation to a description of one or more embodiments or elements
thereof, for example, are explicitly understood to be steps which
can be taken in conjunction with other steps, even though the steps
are not in the same sentence or paragraph. The various possible
combinations and orders of various steps not only do not depart
from the spirit of the inventions disclosed herein, they are
explicitly taught and disclosed by this paragraph and throughout.
Finally, where steps are required to be taken in particular order,
must be taken consecutively with no intervening steps, etc., such
will either be explicitly stated in the text or claim, or will,
again, be apparent to one of ordinary skill in the art.
[0085] Method steps are presented here, numbered for ease of
reference, even though a practitioner of the arts or one of
ordinary skill in the art is capable of discerning these and other
steps from the disclosure supra. Exemplary steps include: 1. a
method of producing fluid from a subterranean well having a
production string positioned downhole in a wellbore extending
through a formation, the method comprising the steps of: a) flowing
production fluid from the formation through an interior passageway
defined in the production string, the production fluid having a
free gas component and a liquid component; b) allowing
uninterrupted production fluid flow through a gas compression
separator assembly positioned along the production string while:
compressing the production fluid in the production string;
separating at least some free gas from the production liquid; and
c) flowing the compressed production fluid to the intake of an ESP.
Additional steps and details regarding possible steps follow. 2.
The method of 1, wherein step (b) further comprises dissolving or
entraining at least a portion of the free gas into the production
liquid. 3. The method of 1-2, wherein step (b) further comprises
venting the separated free gas to the exterior of the production
string at a downhole location. 4. The method of 1-3, wherein the
step of compressing further comprises incrementally compressing the
production fluid using a series of compressor assemblies. 5. The
method of 4, further comprising the step of sequentially reducing
the volumetric fluid flow rate of the production fluid using the
series of compressor assemblies. 6. The method of 4-5, wherein each
compressor assembly of the series has an operating range, and
further comprising compressing the production fluid using a
compressor assembly to within the operating range of a subsequent
compressor assembly. 7. The method of 4-6, wherein the compressor
assemblies have at least one impeller and at least one diffuser. 8.
The method of 4-7, wherein at least one of the compressor
assemblies of the series are assembled in compression. 9. The
method of 4-8, wherein the series of compressor assemblies are
divided into a plurality compression stages, each compression stage
having at least two compressor assemblies, and further comprising
driving at least two compression stages utilizing different
diameter shafts. 10. The method of 1-9, wherein the step of
compressing further includes reducing volumetric flow rate of the
production fluid. 11. The method of 1-10, wherein the step of
compressing further includes increasing production fluid pressure.
12. The method of 1-11, wherein the step of separating free gas
from production liquid further comprises creating a vortex of
production fluid in a fluid chamber. 13. The method of 12, further
comprising forcing lighter production free gas toward the center of
the vortex and heavier production liquid toward the fluid chamber
wall. 14. The method of 1-13, further comprising venting a portion
of free gas through a cross-over tool. 15. The method of 12,
wherein creating the vortex includes the step of rotating at least
one paddle in the fluid chamber. 16. The method of 1-15, further
comprising the step of pumping the compressed production fluid to
the surface using the ESP. 17. The method of 1-16, further
comprising the step of reducing the likelihood of gas lock
occurring in the ESP.
[0086] Exemplary methods of use of the invention are described,
with the understanding that the invention is determined and limited
only by the claims. Those of skill in the art will recognize
additional steps, different order of steps, and that not all steps
need be performed to practice the inventive methods described.
[0087] 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 disclosed apparatus
and methods 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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