U.S. patent application number 16/440902 was filed with the patent office on 2019-09-26 for wellbore pumps in series, including device to separate gas from produced reservoir fluids.
The applicant listed for this patent is Hansen Downhole Pump Solutions AS. Invention is credited to Henning Hansen.
Application Number | 20190292889 16/440902 |
Document ID | / |
Family ID | 60702899 |
Filed Date | 2019-09-26 |
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United States Patent
Application |
20190292889 |
Kind Code |
A1 |
Hansen; Henning |
September 26, 2019 |
WELLBORE PUMPS IN SERIES, INCLUDING DEVICE TO SEPARATE GAS FROM
PRODUCED RESERVOIR FLUIDS
Abstract
A pump system for a wellbore includes a production tubing nested
within a wellbore. At least two pumps are disposed in the
production tubing and are axially spaced apart from each other. One
of the pumps is removable from the production tubing while the
production tubing remains in place. A fluid intake conduit is
disposed outside the production. The fluid intake conduit is in
fluid communication with an interior of the production tubing below
a lower one of the pumps and at a position of an intake of an upper
one of the pumps. At least one fluid discharge conduit is disposed
outside the tubing and inside the wellbore. The at least one fluid
discharge conduit is in fluid communication with the interior of
the production tubing proximate a discharge of the lower one of the
pumps and above the upper one of the pumps.
Inventors: |
Hansen; Henning; (Dolores,
ES) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Hansen Downhole Pump Solutions AS |
Bryne |
|
NO |
|
|
Family ID: |
60702899 |
Appl. No.: |
16/440902 |
Filed: |
June 13, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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PCT/IB2017/057503 |
Nov 29, 2017 |
|
|
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16440902 |
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62440060 |
Dec 29, 2016 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F04D 13/10 20130101;
E21B 43/128 20130101 |
International
Class: |
E21B 43/12 20060101
E21B043/12; F04D 13/10 20060101 F04D013/10 |
Claims
1. A pump system for a wellbore, comprising: a production tubing
disposed in a wellbore; at least two pumps disposed in the
production tubing and axially spaced apart from each other, at
least one of the at least two pumps removable from the production
tubing while the production tubing remains in place in the
wellbore; and at least one fluid intake conduit disposed outside
the production tubing and inside the wellbore, the at least one
fluid intake conduit in fluid communication with and providing a
fluid transport path between an interior of the production tubing
below a lower one of the at least two pumps and at a position of an
intake of an upper one of the at least two pumps; and at least one
fluid discharge conduit disposed outside the tubing and inside the
wellbore, the at least one fluid discharge conduit in fluid
communication with and providing a fluid transport path between the
interior of the production tubing at a discharge of the lower one
of the at least two pumps and either at an intake of or above the
upper one of the at least two pumps.
2. The system of claim 1 wherein at least the upper one of the at
least two pumps is seated in a wet mateable electrical/mechanical
connector disposed in the production tubing.
3. The system of claim 1 wherein both the upper one and the lower
one of the at least two pumps is seated in a respective wet
mateable electrical/mechanical connector disposed in the production
tubing.
4. The system of claim 1 further comprising a gas separator
disposed in the production tubing below the lower one of the at
least two pumps, the gas separator having at least one gas
discharge conduit disposed outside the tubing and inside the
wellbore, the gas discharge conduits in fluid communication with
the interior of the production tubing above the upper one of the at
least two pumps.
5. The system of claim 4 further comprising a booster disposed
above the upper one of the at least two pumps having an intake in
fluid communication with the at least one gas discharge conduit, an
outlet of the booster in fluid communication with an interior of
the production tubing.
6. The system of claim 3 wherein the gas separator comprises an
inner tube nested within an outer tube having fluid entry ports,
the inner tube having fluid entry ports at an axial position below
the fluid entry ports in the outer tube, a seal disposed between
the inner tube and the outer tube disposed at a longitudinal
position above the fluid entry ports in the outer tube, the seal
having at least one gas discharge tube passing therethrough.
7. The system of claim 1 wherein at least the upper one of the at
least two pumps is sealingly engaged to the interior of the
production tubing so as to substantially prevent movement of fluid
between an interior of the production tubing and an exterior of the
at least the upper one of the at least two pumps.
8. The system of claim 1 wherein the at least two pumps comprise
electrically submersible pumps.
9. The system of claim 1 further comprising an annular seal element
disposed between the production tubing and a casing disposed in the
wellbore, the annular seal element disposed at a position below the
lower one of the at least two pumps.
10. The system of claim 1 wherein the lower one of the at least two
pumps is coupled to the production tubing so as to require removal
of the production tubing to remove the lower one of the at least
two pumps from the wellbore.
11. The system of claim 1 further comprising a plurality of fluid
flow conduits each being in fluid communication with an interior of
the production tubing at longitudinal positions corresponding to
fluid communication positions of the at least one fluid intake
conduit.
12. The system of claim 1 further comprising a plurality of fluid
flow conduits each being in fluid communication with an interior of
the production tubing at longitudinal positions corresponding to
fluid communication positions of the at least one fluid discharge
conduit.
13. The system of claim 1 wherein each of the at least two pumps
has a fluid pumping rate enabling lift of a full flow rate of fluid
from the wellbore to the surface, whereby failure of one of the at
least two pumps enables substitution of the other of the at least
two pumps to maintain full fluid flow from the wellbore to the
surface.
14. The system of claim 1 wherein the at least two pumps have an
outer diameter and/or a length such that the at least two pumps are
able to move through a point of maximum dog leg severity in the
wellbore.
15. The system of claim 1 further comprising at least a third pump
disposed in the production tubing intermediate the upper one of the
at least two pumps and the lower one of the at least two pumps, the
at least a third pump having at least one respective fluid intake
conduit disposed outside the production tubing and inside the
wellbore, the at least one respective fluid intake conduit in
communication with the interior of the production tubing below the
lower one of the at least two pumps and at a position of an intake
of the at least a third pump, the at least a third pump having at
least one respective fluid discharge conduit disposed outside the
tubing and inside the wellbore, the at least one fluid discharge
conduit in fluid communication with the interior of the production
tubing proximate a discharge of the at least a third pump and
either proximate the intake of or above the upper one of the at
least two pumps.
16. The system of claim 15 wherein the at least a third pump is
seated in a respective wet mateable electrical/mechanical connector
disposed in the production tubing.
17. The system of claim 16 wherein the at least a third pump is
removable from the production tubing without removing the
production tubing from the wellbore.
18. The system of claim 15 wherein any combination of two of the
upper one of the at least two pumps and the at least a third pump
has a fluid pumping rate enabling lift of a full flow rate of fluid
from the wellbore to the surface, whereby failure of any one of the
at least two pumps and the at least a third pump enables
substitution of the other of the at least two pumps to maintain
full fluid flow from the wellbore to the surface.
19. A method for pumping fluid from a wellbore, comprising:
operating at least one of at least two pumps disposed in a
production tubing disposed in the wellbore, at least one of the at
least two pumps removable from the production tubing while the
production tubing remains in place in the wellbore, at least one
fluid intake conduit disposed outside the production tubing and
inside the wellbore, the at least one fluid intake conduit in fluid
communication with and providing a fluid transport path between an
interior of the production tubing below a lower one of the at least
two pumps and at a position of an intake of an upper one of the at
least two pumps, at least one fluid discharge conduit disposed
outside the tubing and inside the wellbore, the at least one fluid
discharge conduit in fluid communication with and providing a fluid
transport path between the interior of the production tubing at a
discharge of the lower one of the at least two pumps and either at
an intake of or above the upper one of the at least two pumps.
20. The method of claim 19 wherein each of the at least two pumps
has a fluid pumping rate enabling lift of a full flow rate of fluid
from the wellbore to the surface, whereby failure of one of the at
least two pumps enables substitution of the other of the at least
two pumps to maintain full fluid flow from the wellbore to the
surface.
21. The method of claim 19 further comprising operating at least a
third pump disposed in the production tubing intermediate the upper
one of the at least two pumps and the lower one of the at least two
pumps, the at least a third pump having at least one respective
fluid intake conduit disposed outside the production tubing and
inside the open wellbore, the at least one respective fluid intake
conduit in communication with the interior of the production tubing
below the lower one of the at least two pumps and at a position of
an intake of the at least a third pump, the at least a third pump
having at least one respective fluid discharge conduit disposed
outside the tubing and inside the wellbore, the at least one fluid
discharge conduit in fluid communication with the interior of the
production tubing proximate a discharge of the at least a third
pump and either proximate the intake of or above the upper one of
the at least two pumps.
22. The method of claim 21 wherein any combination of two of the
upper one of the at least two pumps and the at least a third pump
has a fluid pumping rate enabling lift of a full flow rate of fluid
from the wellbore to the surface, whereby failure of any one of the
at least two pumps and the at least a third pump enables
substitution of the other of the at least two pumps to maintain
full fluid flow from the wellbore to the surface.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] Continuation of International Application No.
PCT/IB2017/057503 filed on Nov. 29, 2017. Priority is claimed from
U.S. Provisional Application No. 62/440,060 filed on Dec. 29, 2016.
Both the foregoing applications are incorporated herein by
reference in their entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable
NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT
[0003] Not Applicable.
BACKGROUND
[0004] This disclosure relates to the field of producing fluids
from underground wellbores, where the fluids need artificial
assistance to be transported to the surface.
[0005] Wellbores used for the production of fluids disposed in
underground formations (for example from a hydrocarbon reservoir)
to the surface often must be equipped with artificial lift devices
such as downhole pumps to assist pushing fluids to the outlet of
the wellbore proximate the surface. A common pump type is
electrically driven, and is known as an electrical submersible pump
(ESP). To obtain various fluid lift rates to the surface, the
length and dimension of the pump determines the fluid flow rate to
surface that may be obtained. ESP fluid lift flow rates typically
are related to the outer diameter and length of the ESP. Smaller
diameter and smaller length corresponds to lower possible flow
rates; larger outer diameter and longer pumps may have higher
possible flow rates.
[0006] Often wellbores include a conduit called a "casing" that has
a less than optimum internal diameter for an artificial lift system
to be installed, which frequently means that a pump (e.g., an ESP)
of smaller outer dimension than may be desirable must be used, and
correspondingly results in insufficient fluid lift rates to the
surface. Also, wellbores are often deviated (inclined from
vertical), which results in a length restriction for the pump(s);
pumps generally cannot be exposed to large bending as would be
required to install such pumps in a wellbore that has high change
in deviation per unit length ("dog leg severity"). As an example,
the productive reservoirs in the Barents Sea located north of
Norway are at very shallow depths below the seafloor. Highly
inclined and/or horizontal wells are often required to make
producing hydrocarbons from such reservoirs economically feasible.
The dog leg severity of such wells may create challenges in
deploying pumps deep enough in such wells to deliver optimum flow
and reservoir drainage. It should also be noted that such
reservoirs will often produce fluids very close to their bubble
point, further creating a need for having pumps as deep into the
wellbores as possible.
[0007] Another aspect of shallow reservoirs such as may be found in
the Barents Sea is that it is remote from shore, and replacing
pumps that are permanently mounted onto the production tubing will
require lengthy and costly mobilization of a marine drilling unit.
Such conditions result in lost production while waiting for the
marine drilling unit to be mobilized to the well location and made
ready for the well intervention.
[0008] If pumps in subsea wells can be replaced by light
intervention, as for example by wireline or similar, a less costly
vessel can be used. Such vessels will most likely also have much
less mobilization time than marine drilling units, which may
substantially reduce lost production in case of pump failures.
[0009] Hence, there is a need for a solution to the difficulties of
installing pumps in highly inclined wellbores, and in particular
such wellbores located offshore.
[0010] ESPs may suffer from lack of reliability, and therefore it
is an advantage to install several pumps as redundancy in a
wellbore, so that production is not completely stopped in case of
failure of one pump. An alternative, as described in U.S. Pat. No.
9,166,352 issued to Hansen, is to equip a pump with an electrical
wet connect system, so that a pump can be retrieved and installed
without having to retrieve the entire well completion system.
[0011] There are technologies known in the art where power to
operate individual wellbore pumps can be engaged and disengaged
downhole in the wellbore, as for example an hydraulically activated
switch provided by RMS Pumptools, North Meadows Oldmeldrum
Aberdeenshire AB51 0GQ, United Kingdom and described in U.S. Pat.
No. 8,353,352 issued to Leitch. It is also possible to implement a
downhole electronic addressing system, which could be used to
engage and disengage electrical power to individual or several
wellbore pumps. Operation of a downhole addressing system may be
performed using an ESP power cable, or by using a separate cable
that may also be used for downhole sensors and the like. Such a
switching system may be incorporated into an ESP coupler as
described in U.S. Pat. No. 9,166,352 issued to Hansen. Also a
downhole switch is described in U.S. Patent Application Publication
No. 2015/003717, entitled, "Electric submersible pump having a
plurality of motors."
SUMMARY
[0012] In one aspect, the disclosure relates to a pump system for a
wellbore. A pump system according to this aspect of the disclosure
includes a production tubing nested within a casing in a wellbore
or disposed within an open wellbore. At least two pumps are
disposed in the production tubing and axially spaced apart from
each other. At least one of the at least two pumps is removable
from the production tubing while the production tubing remains in
place in the wellbore. At least one fluid intake conduit is
disposed outside the production tubing and inside the wellbore. The
at least one fluid intake conduit is in fluid communication with an
interior of the production tubing below a lower one of the at least
two pumps and at a position of an intake of an upper one of the at
least two pumps. At least one fluid discharge conduit is disposed
outside the tubing and inside the wellbore. The at least one fluid
discharge conduit in fluid communication with the interior of the
production tubing proximate a discharge of the lower one of the at
least two pumps and above the upper one of the at least two
pumps.
[0013] A method for pumping fluid from a wellbore according to
another aspect of the disclosure includes operating at least one of
at least two pumps disposed in a production tubing disposed in the
wellbore. At least one of the at least two pumps is removable from
the production tubing while the production tubing remains in place
in the wellbore, at least one fluid intake conduit disposed outside
the production tubing and inside the wellbore, the at least one
fluid intake conduit in communication with an interior of the
production tubing below a lower one of the at least two pumps and
at a position of an intake of an upper one of the at least two
pumps, at least one fluid discharge conduit disposed outside the
tubing and inside the wellbore, the at least one fluid discharge
conduit in fluid communication with the interior of the production
tubing proximate a discharge of the lower one of the at least two
pumps and either proximate an intake of or above the upper one of
the at least two pumps.
[0014] Other aspects and possible advantages of the present
disclosure will be apparent from the description and claims that
follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] FIG. 1 illustrates a wellbore consisting of a casing with a
production tubing inside, where the production tubing incorporates
several pumps.
[0016] FIGS. 2A, 2B and 2C illustrate a method of installing two
ESPs in tandem, where fluid production from a reservoir enters the
ESPs intakes from the casing side.
[0017] FIG. 3 illustrates a production tubing with several
retrievable pumps placed within the tubing at various depths.
[0018] FIG. 4 illustrates a production tubing with several
non-retrievable pumps placed within the tubing at various
depths.
[0019] FIG. 5 illustrates that a combination of a permanently and
one or more retrievable pumps are also possible, combining what is
illustrated in FIG. 3 and FIG. 4.
[0020] FIG. 6 illustrates a cross section of the wellbore with the
pump (including possible electrical coupler/connection), the
electrical cable and several fluid transport conduits.
[0021] FIGS. 7A and 7B illustrate the difference between using a
pump with a smaller outer diameter and/or shorter length to be able
to be deployed further into high dog leg severity wellbores.
[0022] FIG. 8 illustrates a cross sectional example of a casing
string where an ESP, an electrical wet connect, ESP cable and
bypass tubing strings are shown.
[0023] FIG. 9 illustrates how an ESP assembly may be configured,
including the electric wet connect system.
[0024] FIG. 10 illustrates how a gas separating device may be
incorporated below the fluid distribution to the above mounted
pumps.
[0025] FIG. 11 illustrates a booster system receiving gas from one
or several gas feeding conduit(s), and then discharging the gas
into the produced fluids from one or several wellbore pumps.
[0026] FIG. 12 illustrates a gas separation system located below
the pump system, where the separation system is sealing externally
against the production casing.
DETAILED DESCRIPTION
[0027] The present disclosure describes structures wherein a
plurality of wellbore fluid pumps can be installed in a wellbore as
individual units, where each pump below an uppermost pump transfers
fluids to a location above the uppermost pump, or to an area below
the uppermost pump, if the uppermost pump is capable of pumping the
combined volume delivered from the pumps below. Bypass (flow)
conduits may be provided for transporting reservoir fluids from
below the lowermost pump to one or more pumps mounted above the
lowermost pump, as well as transporting fluids from the various
pumps to a location below and/or above the uppermost pump. One or
several fluid transport tubes may be disposed between each required
pump location may be provided in some embodiments to obtain
increased fluid transport rate to surface. The axial distance along
the wellbore between the various pumps may be different. By
utilizing three pumps, for example, where two pumps in operation
provide sufficient fluid flow rate to surface, provides redundancy
and more reliable production. If one of the two operating pumps
fails, the third pump can be activated to resume the total required
fluid lift rate to surface.
[0028] Using one or more wet connect coupler(s), as for example the
coupler described in patent U.S. Pat. No. 9,166,352 issued to
Hansen, the pumps can be replaced by light wellbore intervention
instead of having to mobilize and use a much more costly drilling
rig.
[0029] In some embodiments, a production packer (annular seal
between a wellbore casing and a nested production tubing) may be
mounted on the production tubing below the pumps, but can also be
mounted on the production tubing above the pumps if required. The
latter method is more complex, because the packer will need to have
bypass devices to enable pass through of the electrical cable.
However, pump packers with annular bypass is a commonly available
technology today.
[0030] In some embodiments, a well completion may consist of a
larger outer diameter, permanently installed ESP capable of lifting
total required fluid flow rate amount of fluid per combined with
one or several retrievable ESPs (e.g., wireline or coiled tubing
retrievable ESPs. The retrievable ESPs may function as a back-up to
the permanently mounted pump, and may also be sized to together be
able to provide the total required fluid flow rate
[0031] In some embodiments, a gas separator may be installed below
the ESPs, where gas may be discharged to an area above the ESPs.
The gas separation system may be retrievable by wireline, coiled
tubing or the like, or may also be permanently mounted as part of
the production tubing.
[0032] While the various embodiments disclosed herein are described
in terms of a wellbore having a casing disposed therein, it will be
appreciated by those skilled in the art that the various aspects of
pump systems according to the present disclosure may be used in
wellbores not having casing ("open wellbores"), and the scope of
the disclosure should be construed accordingly.
[0033] FIG. 1 illustrates an example wellbore having a casing 14
disposed in the wellbore (not shown separately) to hydraulically
isolate formations disposed outside the casing 14 and to maintain
mechanical integrity of the wellbore. The casing 14 may comprise a
nested production tubing 12 inside, where the production tubing 12
includes a plurality of pumps, for example, electrical submersible
pumps (ESPs). In the present example embodiment the tubing 12
comprises three axially spaced apart pumps, shown at 10A, 10B and
10C, respectively. An annular seal 16, often referred to as a
packer, production packer or a tie-back seal stem, may be located
proximate the lower end of the production tubing 12 in the annular
space between the production tubing 12 and the casing 14. The pumps
10A, 10B, 10C may be disposed in the production tubing 12 above the
annular seal 16. Each pump 10A, 10B, 10C has a dedicated fluid path
from the wellbore below the annular seal 16 to the respective
intake of each pump 10A, 10B, 10C. In the present embodiment, the
lowermost pump 10C may have its intake path through the part of the
production tubing 12 disposed below the lowermost pump 10C. The
middle 10B and upper 10A pumps may have corresponding intake flow
lines 22B, 22A that are fluidly connected, at 22B1 and 22A1,
respectively to the interior of the production tubing 12 below the
lowermost pump 10C. The lowermost pump 10C and middle pump 10B may
each have as well a respective fluid discharge conduit 24C, 24B
above each pump 10C, 10B Such fluid discharge conduits 24C, 24B may
be fluidly connected to the interior of the production tubing 12
above the uppermost pump 10A at connections 24C1, 24B1,
respectively. Each fluid intake flow line 22A, 22B as well as each
fluid discharge conduit 24B, 24C may consist of a plurality of
individual conduits disposed in the annular space between the
casing 14 an the production tubing 12 lines to obtain high fluid
flow capability with as small outer total diameter of the pumps
10A, 10B, 10C and lines 22A, 22B, 24A, 24B as practical when the
components are assembled and inserted into the casing 14. If the
pumps 10A, 10B, 10C are suitably sized for flow rate, if one of the
pumps fails, such failure does not affect the operation of the
other pumps, and full fluid flow rate from the wellbore to surface
may be maintained. It is important to understand that the drawings
are not to scale. Also, pumps of a smaller dimension can be used,
where the required total fluid flow rate is obtained by most or all
pumps being operational. Also, it should be understood that each
pump 10A, 10B, 10C may have one or several fluid flow conduits to
and/or from each respective intake and discharge locations
described above. Intake and discharge locations for the respective
fluid flow conduits will depend on the configuration of and the
number of pumps used in any particular embodiment.
[0034] In the example embodiment shown in FIG. 1, the production
tubing 12 may comprise a wet mateable electrical and mechanical
coupler 18A, 18B, 18C for seating each respective pump 10A, 10B,
10C and making electrical connection to each respective pump 10A,
10B, 10C. Furthermore, the lines 22A, 22B, 24A, 24B may be affixed
to the production tubing 12 prior to or during insertion of the
production tubing 12 into the casing 14. The wet mateable
electrical and mechanical couplers 18A, 18B, 18C may be
substantially as described in U.S. Pat. No. 9,166,352 issued to
Hansen. In such case, the pumps 10A, 10B, 10C may be inserted into
and seated in their respective positions within the production
tubing 12 by means of conveyance such as wireline (armored
electrical cable), coiled tubing or jointed tubing. The pumps 10A,
10B 10C may be likewise removed from the production tubing if and
as necessary. It will be appreciated by those skilled in the art
that using wireline conveyance for the pumps 10A, 10B, 10C may
provide operational advantages such as lower transportation cost
and lower operating cost.
[0035] FIGS. 2A, 2B and 2C illustrate a known configuration for
installing multiple ESPs 10A, 10B in tandem. The pumps 10A, 10 are
disposed outside the production tubing 12 and have their respective
intakes in fluid communication with the interior of the casing (14
in FIG. 1). Discharge from each pump 10A, 10B is connected to the
interior of the production tubing using a Y-connector 28 coupled
within the production tubing 12 along one leg of the Y-connector 28
and having a coupling to the discharge of each pump 10A, 10B
through the other leg of the Y connector 28. The drawback of the
configuration shown in FIGS. 2A, 2B and 2C is that the casing (14
in FIG. 1) is subjected to flow erosion because of high fluid flow
velocity in the annular space, as well as having a Y-tool 28 on top
of each pump 10A, 10B. Another possible drawback is that the tubing
connected leg of each Y-connector 28 needs to be large enough to
allow installation and retrieval of a blanking plug 27, which
reduces the amount of room available for the pumps 10A, 10B.
Another typical method is to mount an outer shroud on a ESP
assembly, as an alternative to the bypass tube approach described
in this patent application. Using bypass tubes will allow more room
for the ESP, and therefore has an advantage to using a shroud.
Also, using a shroud prevents the ability to utilize retrievable
ESP's.
[0036] FIG. 3 illustrates a production tubing with several
retrievable pumps 10A. 10B, 10C placed within the production tubing
12 at various axial positions along the interior of the production
tubing 12. The retrievable pumps 10A, 10B, 10C can be pulled to
surface from within the production tubing 12, as well as installed
through same, without having to pull the production tubing 12 to
the surface. A respective electrical wet mateable coupler 18A, 18B,
18C for each pump 10A, 10B, 10C is preinstalled in the production
tubing 12, being for example the type as described in U.S. Pat. No.
9,166,352 issued Hansen. Fluid intake and discharge tubes may be
similar to those as explained with reference to FIG. 1. Being
retrievable pumps, a sealing system on each pump is required to
eliminate any unwanted cross flow and leakages.
[0037] FIG. 4 illustrates a production tubing 12 with several
non-retrievable pumps 110A, 110B, 110C placed within the production
tubing 12 at various axial positions. In case of failure of one or
more of the pumps 110A, 110B, 110C, the production tubing 12 will
need to be pulled to the surface for replacement of any of the
pumps. The fluid intake and discharge tubes may be substantially as
explained with reference to FIG. 1.
[0038] FIG. 5 illustrates that a combination of a permanently 110C
and one or more retrievable 10A, 10B pumps are also possible,
combining what is illustrated in FIG. 3 and FIG. 4. Here, the
permanently mounted pump 110C can be capable of lifting the total
required fluid flow rate to the surface, where back-up is provided
by one or several retrievable pumps 10A, 10B that would also be
able to in combination lift the total required fluid flow rate to
the surface. In case of failure or lack of performance of the
permanent pump 110C, the back-up pumps 10A, 10B can be engaged. If
one or several of the back-up pumps 10A, 10B fail also, it is
possible to replace them without having to remove the production
tubing 12. Flow lines for intake and discharge of the pumps 10A.
10B, 110C may be substantially as explained with reference to FIG.
1. Similarly, each of the retrievable pumps 10A, 10B may be seated
in a respective wet mateable connector 18A, 18B also as explained
with reference to FIG. 1.
[0039] FIG. 6 illustrates a cross section of the wellbore with one
of the pumps, for example pump 10B in FIG. 1 including a wet
mateable electrical/mechanical coupler 18B, an electrical cable 30
and several fluid transport conduits 22A, 22B, 24A, 24B as
explained with reference to FIG. 1.
[0040] FIGS. 7A and 7B illustrate the difference in depth to which
a pump may be moved through production tubing 12 if the pump has a
length and/or diameter according to the present disclosure. In FIG.
7A a conventional, large diameter pump 110 is shown being inserted
into the production tubing 12 and being unable to pass a point 32
in the wellbore where the dog leg severity is sufficient to prevent
further passage of the pump 110. In FIG. 7B, by using a pump 10
with a smaller outer diameter and/or less length, the pump 10 may
be able to pass the point 32 where dog leg severity stops a larger
diameter and/or longer pump (as shown in FIG. 7A).
[0041] FIG. 8 illustrates a cross section of a casing 14 where an
ESP 10, a wet mateable electrical/mechanical connector 18, ESP
cable 30 and flow conduits 22, 24 are shown. The example shown in
FIG. 8 is based on an ESP manufactured by Baker Hughes,
Incorporated, Houston, Tex., under model designation PASS Slimline
3.38. Similar ESPs may be available from other manufacturers. This
type of ESP has a relatively small outer diameter, but is still
able to lift 2,500 barrels of wellbore fluid per day to the
surface. If there is a requirement for 6-7,000 barrels of wellbore
fluid per day to be lifted to surface per day, then for example,
three of such ESPs may be installed in a production tubing
substantially as explained with reference to FIGS. 1 and 3. The
installation may also include light intervention replaceable ESPs,
where each ESP would include a wet mateable electrical/mechanical
connector, for example, as explained with reference to FIGS. 1 and
3.
[0042] FIG. 9 illustrates how an ESP assembly 10A, equivalent to
the uppermost pump shown in FIG. 1 may be removably placed within a
segment (joint) of the production tubing 12. The ESP assembly 10A
may be of types known in the art and may comprise a sensor module
10A7 (having e.g., pressure, temperature and capacitance sensors),
a motor section 10A6, a seal (protector) section 108A, a pump
section (e.g., a centrifugal or progressive cavity pump), a locking
module section 10A3 to axially lock the pump assembly 10A in the
production tubing 12 and a fluid discharge section 10A2. Some
embodiments of the ESP assembly 10A may comprise a fishing head
10A1 to enable retrieval of the ESP assembly 10A using a wireline
"fishing" head attached to the end of an armored electrical cable.
The production tubing 12 may be configured, including the wet
mateable electrical/mechanical connector 18, substantially as
described with reference to FIG. 1 and FIG. 3. Fluid from the
wellbore will be delivered to the pump intake through the flow
line(s) 22A mounted externally on the production tubing 12. The
pump section 10A5 will deliver fluid upwardly to the surface
through the discharge section 10A2 of the ESP system 10A. Even
though the locking module 10A3 is illustrated in FIG. 9 to be
located below the discharge section 10A2, the locking module 10A3
may be disposed at any axial location along the ESP assembly 10A.
The wet mateable connector 18 routes electrical power to the ESP
system 10A. The discharge section 10A2 may also be on the side of
the ESP assembly 10A, discharging fluids into one or several fluid
discharge lines (see FIG. 1) mounted externally on the production
tubing 12. The wet mateable connector 18 may comprise male
connector contacts 18-1 on the ESP system 10A and female connector
contacts 18-2 on the connector portion disposed in the production
tubing 12. A seal section 10A-8 may stop fluid movement axially
within the production tubing 12 along the exterior of the ESP
system 10A, so that all fluid discharged by the ESP system 10A may
be moved into the production tubing 12 in a direction toward the
surface.
[0043] FIG. 10 illustrates a system similar to the system shown in
and explained with reference to FIG. 1 with the inclusion of a gas
separator 34 in the production tubing 12 below the intake of the
lowermost pump 10C. The gas separator 34 device may be of a
retrievable type landed within the production tubing 12, or it may
be a permanent component as part of the production tubing 12. Gas
is discharged from the gas separator 34 to one or more gas
discharge tubes 36 mounted externally on the production tubing 12,
extending to a location axially above the pumps 10A, 10B, 10C.
Having the gas separator 34 may increase the operating efficiency
of the pumps 10A, 10B, 10C by reducing cavitation or gas locking of
the pumps 10A, 10B, 10C.
[0044] FIG. 11 illustrates a booster system 38 receiving gas at an
inlet thereof from one or several gas feeding conduit(s) 36, for
example as explained with reference to FIG. 10, and then
discharging the gas into the produced fluids from one or several
wellbore pumps, e.g., 10A in FIG. 11. The booster system 38 may be
powered by an electrical cable, e.g., 30, by hydraulic power fluid
supplied from the surface through one or several hydraulic control
lines, or by the fluid discharged from one or several wellbore
pumps located below the booster 38. FIG. 11 omits possible fluid
discharge and intake flow lines from wellbore pumps that can be
located in the wellbore below the illustrated pump 10A for clarity
of the illustration. The booster 38 shown in FIG. 11 is applicable
to any system as described herein, specifically including, but
without limitation, those shown in and explained with reference to
FIG. 1, FIG. 3, FIG. 4 and FIG. 10. The booster's function is to
draw in gas from below the pump(s) and then pressurize the gas
enough for the gas to be discharged into the production tubing 12
above the pump(s).
[0045] FIG. 12 illustrates an example embodiment of a gas separator
such as shown in FIG. 10 in more detail. The gas separator 34 may
seal externally against the interior of the casing 14. Fluids and
gas 46 from a reservoir flows into the gas separator 36 through
suitable openings 116A in a lower packer 116 to an area between an
inner tube 34A and an outer tube 34B of the gas separator 34.
Thereafter the fluids and gas 46 exit in the upper section into the
area outside the gas separator 34, followed by traveling to intake
ports in the lower side of the separator 34. This results in gas 40
separating and rising to the upper section of the gas separator 34,
and then entering through an upper packer 216 to, for example, one
or several gas discharge tubes 36 extending to the surface, or
coupled to an area above the wellbore pump(s) as described and
explained with reference to FIGS. 10 and 11. It should be noted
that instead of having fluids and gas in contact with the casing 14
outside the gas separator 34, the fluids and gas may also be
contained within an outer concentric housing, or within one or
several tubes mounted externally.
[0046] Although only a few examples have been described in detail
above, those skilled in the art will readily appreciate that many
modifications are possible in the examples. Accordingly, all such
modifications are intended to be included within the scope of this
disclosure as defined in the following claims.
* * * * *