U.S. patent application number 15/713394 was filed with the patent office on 2019-03-28 for downhole motor-pump assembly.
The applicant listed for this patent is Mark Krpec, David Tilley. Invention is credited to Mark Krpec, David Tilley.
Application Number | 20190093654 15/713394 |
Document ID | / |
Family ID | 65806544 |
Filed Date | 2019-03-28 |
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United States Patent
Application |
20190093654 |
Kind Code |
A1 |
Krpec; Mark ; et
al. |
March 28, 2019 |
DOWNHOLE MOTOR-PUMP ASSEMBLY
Abstract
A downhole motor-pump assembly disposed within a tubular string
includes a rotor and a stator. The rotor has a first rotor portion
and a second rotor portion. The first rotor portion has a first
geometrical shape and the second rotor portion has a second
geometrical shape. The first geometrical shape differs from the
second geometrical shape. The stator has a first stator section and
a second stator section. The first stator section is spaced from
the second stator section by a gapped region. The first rotor
portion is located within the first stator section and the second
rotor potion is located within the second stator section. The
differing geometry causes a difference in displacement in the first
and second sections per revolution of the rotor. Therefore the
difference in displacement must be made up and is induced into the
tool at the gap or drillings between sections, and this additional
volume is effectively pumped.
Inventors: |
Krpec; Mark; (Fulshear,
TX) ; Tilley; David; (Franklin, LA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Krpec; Mark
Tilley; David |
Fulshear
Franklin |
TX
LA |
US
US |
|
|
Family ID: |
65806544 |
Appl. No.: |
15/713394 |
Filed: |
September 22, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F04C 2/1071 20130101;
F04C 2240/20 20130101; E21B 43/126 20130101; F04C 13/008 20130101;
F04C 2240/10 20130101; E21B 4/02 20130101; F03C 2/08 20130101; E21B
43/128 20130101; F04C 11/008 20130101 |
International
Class: |
F04C 11/00 20060101
F04C011/00; E21B 43/12 20060101 E21B043/12; E21B 43/08 20060101
E21B043/08; F04C 13/00 20060101 F04C013/00 |
Claims
1. A downhole motor-pump assembly disposed within a tubular string,
the motor-pump assembly comprising: a rotor, the rotor having a
first rotor portion and a second rotor portion, the first rotor
portion having a first geometrical shape and the second rotor
portion having a second geometrical shape, the first geometrical
shape differing from the second geometrical shape; and a stator
having a first stator section and a second stator section, the
first stator section being spaced from the second stator section by
a gapped region, wherein the first rotor portion is located within
the first stator section and the second rotor portion is located
within the second stator section.
2. The downhole motor-pump assembly of claim 1 wherein the rotor is
configured such that the first geometrical shape displaces a first
volume of fluid upon rotation of the rotor and the second
geometrical shape displaces a second volume of fluid upon rotation
of the rotor.
3. The downhole motor-pump assembly of claim 2 wherein the second
volume of fluid is greater than the first volume of fluid.
4. The downhole motor-pump assembly of claim 1 wherein the rotor is
configured such that the first rotor section defines a first
orbital path upon rotation of the rotor and the second rotor
section defines a second orbital path upon rotation of the rotor,
the first orbital path and second orbital path being substantially
similar to each other, allowing the rotor sections to be common and
rigid.
5. The downhole motor-pump assembly of claim 1 wherein the rotor
freely rotates within the stator.
6. The downhole motor-pump assembly of claim 1 wherein the first
stator section has a first internal profile that is substantially
similar to the first geometrical shape and the second stator
section has a second internal profile that is substantially similar
to the second geometrical shape.
7. The downhole motor-pump assembly of claim 1 wherein the rotor is
a single, one-piece member.
8. The downhole motor-pump assembly of claim 1 wherein the rotor is
configured to be rotated by fluid flowing through the tubular
string.
9. A tubular string comprising: a downhole motor-pump assembly, the
downhole motor-pump assembly including: a stator, the stator having
a first stator section and a second stator section, the first
stator section being spaced from the second stator section by a
gapped region; and a rotor, wherein the rotor is configured to
rotate freely within the stator; and a string body, wherein the
downhole motor-pump assembly is disposed within the string body and
configured such that the rotor rotates within the stator when fluid
is urged downstream within the tubular string.
10. The tubular string of claim 9 wherein the rotor has a first
rotor portion and a second rotor portion, the first rotor portion
having a first geometrical shape and the second rotor portion
having a second geometrical shape, the first geometrical shape
differing from the second geometrical shape.
11. The tubular string of claim 10 wherein the rotor is a single,
one-piece member.
12. The tubular string of claim 10 wherein the string body includes
a pump opening fluidly connected to the gapped region, the pump
opening located downstream of the downhole motor-pump assembly.
13. The tubular string of claim 12 wherein the pump opening is
configured to enable wellbore fluid and debris to be pumped
therethrough.
14. The tubular string of claim 13 wherein the tubular string
includes a filter positioned between the gapped region and the pump
opening.
15. The tubular string of claim 14 wherein the filter is configured
to enable wellbore fluid to pass therethrough while preventing
passage of debris particles.
16. The tubular string of claim 12 wherein the downhole motor-pump
assembly comprises an inlet opening and an outlet opening,
17. The tubular string of claim 16 wherein the gapped region is
located between the inlet and outlet openings.
18. A downhole motor-pump assembly comprising: a stator having a
first stator section and a second stator section; and a single
rotor; wherein the single rotor is positioned within the first and
second stator sections, the downhole motor-pump assembly being
devoid of any wobble shafts or couplings.
19. The downhole motor-pump assembly of claim 18 further comprising
a thrust bearing.
20. The downhole motor-pump assembly of claim 19 wherein the thrust
bearing is configured to transfer any unbalanced thrust load
associated with rotation of the single rotor.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. Provisional Patent
Application Ser. No. 62/399,105, filed on Sep. 23, 2016, which is
herein incorporated by reference in its entirety.
BACKGROUND
Field
[0002] Embodiments of the present disclosure generally relate to a
downhole motor-pump assembly.
Description of the Related Art
[0003] It is known within the prior art to use a downhole motor
(e.g., a drilling motor) and/or a downhole pump disposed within a
drill string. In many situations, however, the design of the
downhole motor is complex and contains numerous components in
addition to a stator and a rotor, such as long torsional shaft
drives, plungers, wobble shafts, bearings, and/or couplings.
Additionally, the downhole pump is usually a separate component
from the downhole motor. Consequently, there is a need for a
simpler downhole motor-pump assembly, especially where the motive
and pumped fluids can be combined before the pump discharge.
SUMMARY
[0004] A first embodiment of the present disclosure is a downhole
motor-pump assembly disposed within a tubular string including a
rotor and a stator. The rotor has a first rotor portion and a
second rotor portion. The first rotor portion has a first
geometrical shape and the second rotor portion has a second
geometrical shape. The first geometrical shape differs from the
second geometrical shape. The stator has a first stator section and
a second stator section. The first stator section is spaced from
the second stator section by a gapped region. The rotor is located
within the stator and configured to be rotated by fluid flowing
downstream within the tubular string.
[0005] Another embodiment of the present disclosure is a tubular
string including a downhole motor-pump assembly and a string body.
The downhole motor-pump assembly includes a stator and a rotor. The
stator has a first stator section and a second stator section. The
first stator section is spaced from the second stator section by a
gapped region. The rotor is configured to rotate freely within the
stator. The downhole motor-pump assembly is disposed within the
string body and configured such that the rotor rotates within the
stator when fluid is urged downstream within the tubular
string.
[0006] Another embodiment of the present disclosure is a downhole
motor-pump assembly including a stator and a single rotor. The
stator has a first stator section and a second stator section. The
single rotor is positioned within the first and second stator
sections. The downhole motor-pump assembly is devoid of any wobble
shafts or couplings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] So that the manner in which the above recited features of
the present disclosure can be understood in detail, a more
particular description of the disclosure, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only exemplary embodiments
and are therefore not to be considered limiting of its scope, and
may admit to other equally effective embodiments.
[0008] FIG. 1 illustrates a first embodiment of a downhole
motor-pump assembly disposed within a tubular string in accordance
with the present disclosure.
[0009] FIG. 2 illustrates fluid flow paths associated with the
downhole motor-pump assembly shown in FIG. 1.
[0010] FIG. 3 illustrates a second embodiment of a downhole
motor-pump assembly disposed within a tubular string in accordance
with the present disclosure.
[0011] FIG. 4 illustrates fluid flow paths associated with the
downhole motor-pump assembly shown in FIG. 3.
[0012] To facilitate understanding, identical reference numerals
have been used, where possible, to designate identical elements
that are common to the figures. It is contemplated that elements
and features of one embodiment may be beneficially incorporated in
other embodiments without further recitation. It is contemplated
that elements and features of one embodiment may be beneficially
incorporated in other embodiments without further recitation.
DETAILED DESCRIPTION
[0013] Embodiments described herein relate to a downhole motor-pump
assembly disposed within a tubular string. The downhole motor-pump
assembly may comprise a rotor and a stator. The rotor may have a
first rotor portion and a second rotor portion. The first rotor
portion may have a first geometrical shape, and the second rotor
portion may have a second geometrical shape. The first geometrical
shape may differ from the second geometrical shape. The rotor may
be configured to rotate freely within the stator. The stator may
have a first stator section and a second stator section. The first
stator section may be spaced from the second stator section by a
gapped region. The rotor may be located within the stator and
configured to be rotated by fluid flowing downstream within the
tubular string. In operation of the assembly, the first rotor
portion and the first stator section may collectively function as a
motor, and the second rotor portion and the second stator section
may collectively function as a pump.
[0014] FIGS. 1 and 2 illustrate a first embodiment of the present
disclosure in which a downhole motor-pump assembly 100 is disposed
within a tubular string 102 (e.g., Work or Drill String) for the
purpose of downhole debris removal. In well drilling and completion
operations, there are applications requiring the picking up of
debris in a wellbore. At times, fluid within the well cannot be
pumped at a high enough flow rate to flush out the debris and
circulate the debris back to a sea surface. For example, the
physical limits of the wellbore may prevent fluid from being pumped
at a flow rate that flushes out the debris without damaging the
wellbore from the resulting pressures. The downhole motor-pump
assembly 100 may be utilized to address some of these problems.
[0015] The downhole motor-pump assembly 100 includes a rotor 104
and a stator 106. The downhole motor-pump assembly includes an
inlet opening 105 and an outlet opening 107. The rotor 104 has a
first rotor portion 108 and a second rotor portion 110. In the
embodiment shown in FIG. 1, the second rotor portion 110 is
downstream of the first rotor portion 108. The first rotor portion
108 has a first geometrical shape and the second rotor portion 110
has a second geometrical shape. The first geometrical shape differs
from the second geometrical shape. As seen in FIG. 1, the first
geometrical shape has a pitch P, with the pitch P being the
distance between two adjacent profile peaks within the first rotor
portion 108. The pitch P is substantially constant throughout the
first rotor portion 108. A pitch of the second geometrical shape is
greater than pitch P. For example, as seen in FIG. 1, the pitch of
the second geometrical shape is about three times the pitch P of
the first geometrical shape. In other words, the pitch of the
second geometrical shape is 3P. The pitch 3P of the second
geometrical shape is the distance between two adjacent profile
peaks within the second rotor portion 110. The pitch 3P is
substantially constant throughout the second rotor portion 110.
Because the first geometrical shape differs from the second
geometrical shape, the volume of fluid displaced per revolution of
the rotor 104 by the first rotor portion 108 differs from the
volume of fluid displaced per revolution of the rotor by the second
rotor portion 110. In the embodiment shown in FIG. 1, the volume of
fluid displaced per revolution of the rotor by the second rotor
portion 110 is greater than the volume of fluid displaced per
revolution of the rotor by the first rotor portion 108. Revolution
of the first rotor portion 108 defines a first orbital path and
revolution of the second rotor portion 110 defines a second orbital
path, the first and second orbital paths being substantially
similar to each other. It is to be understood geometrical shapes
other the ones shown in FIG. 1 may be used for the first rotor
portion 108 and the second rotor portion 110.
[0016] In one embodiment, the rotor 104 may be a single, one-piece
element. It is to be understood, however, that the rotor 104 may be
comprised of two or more elements coupled together. For example,
the first rotor portion 108 may be a first element and the second
rotor portion 110 may be a second element, with the first and
second elements being coupled together. It is also to be understood
that rotor 104 may include more than two rotor sections. For
example, the rotor 104 may include a third rotor section positioned
between the first and second rotor sections, with the third rotor
section being of a third geometrical shape. In such a situation,
the third geometrical shape may differ from the first geometrical
shape, from the second geometrical shape, or from both the first
and second geometrical shapes.
[0017] The stator 106 has a first stator section 112 and a second
stator section 114. The first stator section 112 is spaced from the
second stator section 114 by a gapped region 116. The rotor 104 is
located within the stator 106 and configured to be rotated by fluid
flowing downstream within the tubular string 102. More
specifically, the first rotor portion 108 is located within the
first stator section 112 and the second rotor portion 110 is
located within the second stator section 114. The first stator
section 112 has a first internal profile that is substantially
similar to the first geometrical shape of the first rotor portion
108 and the second stator section 114 has a second internal profile
that is substantially similar to the second geometrical shape of
the second rotor portion 110. The rotor 104 is freely orbiting
within the stator 106 and need not be coupled to any further device
to perform its function, thereby eliminating the need of any wobble
shafts, radial bearings, and/or couplings. A downstream end of
rotor 104 rests on a platform 120 of the tubular string 102.
Platform 120 may include a thrust bearing or collar to transfer any
thrust load of the rotor 104. Note that the common rotor and the
port arrangement cause a substantial balancing of thrust forces
within the pump and motor assembly, lessening the requirements of
the thrust bearing.
[0018] The tubular string 102 includes a pump opening 118 located
downstream of the downhole motor-pump assembly 100. The tubular
string 102 is configured such that the outlet opening 107, the pump
opening 118, and the gapped or ported region 116 are fluidly
connected to each other to form a localized circulation loop. The
gapped or ported region 116 creates a suction force as fluid is
pumped downstream through the second stator section 114. The
suction force pulls wellbore fluid and debris particles DP located
within the well into the tubular string 102 via the pump opening
118. As can be seen in FIG. 1, the tubular string 102 may further
include a filter 121. The filter 121 is located downstream of the
gapped region 116 and is configured to enable wellbore fluid to
pass therethrough while preventing passage of debris particles DP.
The tubular string 102 may further include a one-way valve (not
shown) positioned adjacent the pump opening 118. The one-way valve
may open inwardly and be configured to enable wellbore fluid and
debris particles to enter the tubular string 102 as a result of the
suction force generated by fluid flowing downstream through the
stator 106 while preventing the debris particles from being
expelled from the pump opening 118 on shut-down.
[0019] In operation, the first rotor portion 108 and the first
stator section 112 collectively function as a motor of the downhole
motor-pump assembly 100, and the second rotor portion 110 and the
second stator section 114 collectively function as a pump of the
downhole motor-pump assembly. The tubular string 102 is first
lowered to a desired depth within the wellbore. A driving fluid may
then be urged downstream through the tubular string 102 at a flow
rate of, for example, approximately 3 barrels per minute (i.e.,
BPM), and a pressure of approximately 1000 psi at inlet opening
105. As the driving fluid is urged downstream, it causes the rotor
104 to freely rotate within the stator 106, as the rotor is not
connected to the stator via any wobble shafts, bearings, and/or
couplings. As the rotor 106 rotates, the second rotor portion 110
within the second stator section 114 displaces a larger volume of
fluid per revolution of the rotor than the first rotor portion 108
within the first stator section 112. Consequently, the second rotor
portion 110 and the second stator section 114 would generate a
suction force at the gapped or ported region 116 to induce the
necessary additional flow to satisfy this section's additional flow
requirement. The pressure at the gapped region 116 is then for
example, approximately 0 psi. The suction force generated at the
gapped region 116 creates a flow of wellbore fluid through the
gapped region 116 and into the second stator section 114. Because
the outlet opening 107, the pump opening 118, and the gapped region
116 are fluidly connected to each other, it generates the
previously discussed localized circulation loop that can be seen in
FIG. 2.
[0020] For example, during operation of the downhole motor-pump
assembly 100, the flow of additional wellbore fluid passing through
the gapped region 116 could have a flow rate of approximately 6
BPM. Consequently, the flow rate of fluid flowing through the
second stator section 114 will be greater than the flow rate of
fluid flowing through the first stator section 112. For example,
the flow rate of fluid flowing through the first stator section 112
may be approximately 3 BPM while the flow rate of fluid flowing
through the second stator section 114 may be approximately 9 BPM.
The driving fluid urged downstream through the tubular string 102
from, for example, a surface pump is combined with fluid pumped
through the gapped region 116. As discussed above, the driving
fluid entering the inlet opening 105 may exert a pressure of
approximately 1000 psi while the combined fluid exiting the outlet
opening 107 may have a lower pressure of approximately 300 psi, but
with an inversely proportionate volume increase.
[0021] As can be seen in FIG. 2, some of the fluid exiting the
outlet opening will flow upstream to the surface and some of the
fluid will flow downstream because of the suction force and flow
requirement at the gapped region 116 and generate the localized
circulation loop. For example, fluid exiting the outlet opening 107
may have a flow rate of approximately 3 BPM to the surface and a
flow rate of approximately 6 BPM downstream. Because of the suction
force generated at the gapped region 116 and the localized
circulation loop, wellbore fluid and debris particles DP will be
pulled into the tubular string 102. As discussed above, the filter
121 will then permit passage of wellbore fluid therethrough while
preventing passage of debris particles DP pulled into the tubular
string 102.
[0022] In this manner, the tubular string 102 and the downhole
motor-pump assembly 100 enable the removal of debris from the
wellbore. Moreover, the tubular string 102 and the downhole
motor-pump assembly 100 provide for the ability to control and
monitor downhole performance within the well from a sea surface as
a result of the pressures and flow rates seen at the surface
correlating to those of the pumped fluid by the downhole pump. This
is only possible with such positive displacement pumps. Another
advantage of the downhole motor-pump assembly 100 is the reduced
fluid pressure of a localized flow loop. The alternative requires
flow to surface and a correspondingly higher pressure to drive such
a flow path, which can be detrimental to the well. In addition, the
progressive cavity pump does not shear the fluid as centrifugal
pumps or eductors do. This allows for viscous fluids and gels that
are required for certain downhole operations to be pumped
downstream without being damaged.
[0023] FIGS. 3 and 4 illustrate a second embodiment in which the
downhole motor-pump assembly 100 is disposed within a tubular
string 202 (e.g., drill string) for the purpose of downhole
production pumping. Tubular string 202 is substantially similar to
tubular string 102, with the exception that tubular string 202 does
not include a filter. Moreover, a sealing element 204 is positioned
within the wellbore adjacent the pump opening 118. In this
situation, the outlet opening 107, the pump opening 118, and the
gapped region 116 are not fluidly connected to each other to create
a localized circulation flow loop, as was the situation in FIG. 1.
Instead, sealing element 204 isolates the outlet opening 107 from
the pump opening 118. A suction force is still generated at the
gapped region 116 as a result of the rotation of the second rotor
portion 110 within the second stator section 114. As can be seen in
FIG. 4, the suction force generated at the gapped region 116
produces a production flow of gas and/or liquid hydrocarbons from
the wellbore region downstream of the sealing element 204. For
example, if fluid is urged downstream into the stator 106 through
inlet opening 105 at a flow rate of approximately 3 BPM at a
pressure of approximately 1000 psi, a combined flow through the
pump section of 9 bpm, would be generated and consequently the
difference would produce a production flow with a flow rate of
approximately 6 BPM.
[0024] The produced flow will flow upstream into the tubular string
202 via pump opening 118 and through the gapped region 116 at the
flow rate of approximately 6 BPM and combine with the driving fluid
being urged downstream through the inlet opening 105 at a flow rate
of approximately 3 BPM. Consequently, the combined fluid will exit
the stator 106 via the outlet opening 107 at a flow rate of
approximately 9 BPM and at a pressure of approximately 300 psi. The
combined fluid will then flow upstream, for example, to a surface,
at the flow rate of 9 BPM because sealing element 204 prevents
fluid from flowing downstream. Combining the production flow with
the driving fluid can be particularly beneficial when another
well's higher pressure, higher temperature, or less viscous product
can be used as the driving fluid urged downstream through the inlet
opening 105. Doing so may reduce the viscosity of the combined
fluids and enhance the production flow of the well in which the
tubular string 202 is disposed.
[0025] While the foregoing is directed to embodiments of the
present disclosure, other and further embodiments of the disclosure
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *