Note: Descriptions are shown in the official language in which they were submitted.
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WELLBORE PUMPS IN SERIES, INCLUDING DEVICE TO SEPARATE
GAS FROM PRODUCED RESERVOIR FLUIDS
Background
100011 This disclosure relates to the field of producing fluids from
underground
wellbores, where the fluids need artificial assistance to be transported to
the surface.
100021 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.
[0003] 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
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to their bubble point, further creating a need for having pumps as deep into
the wellbores
as possible.
100041 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.
100051 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.
100061 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.
[00071 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. Patent
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.
100081 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 OGQ, United Kingdom and described in U.S. Patent
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. Patent No. 9,166,352 issued to
Hansen. Also a
2
downhole switch is described in U.S. Patent Application Publication No.
2015/003717,
entitled, "Electric submersible pump having a plurality of motors."
Summary
[0009] In one aspect, the disclosure relates to 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 pump.
[0010] 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
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.
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100111 Other aspects and possible advantages of the present disclosure will
be apparent
from the description and claims that follow.
Brief Description of the Drawings
[0012] Fig. 1 illustrates a wellbore consisting of a casing with a
production tubing inside,
where the production tubing incorporates several pumps.
[0013] Fig. 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.
[0014] Fig. 3 illustrates a production tubing with several retrievable
pumps placed within
the tubing at various depths.
[0015] Fig. 4 illustrates a production tubing with several non-retrievable
pumps placed
within the tubing at various depths.
[0016] 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.
100171 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.
[0018] Fig. 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.
100191 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.
[0020] Fig. 9 illustrates how an ESP assembly may be configured, including
the electric
wet connect system.
[0021] Fig. 10 illustrates how a gas separating device may be incorporated
below the
fluid distribution to the above mounted pumps.
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100221 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.
[0023] 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
[0024] 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.
[00011 Using one or more wet connect coupler(s), as for example the coupler
described
in patent U.S. Patent 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.
[0002] 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
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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.
100031 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
[0004] 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.
[0005] 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.
[0006] 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
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the annular seal 16 to the respective intake of each pump l OA, 10B, 10C. In
the present
embodiment, the lowermost pump IOC 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.
100071 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. Patent No. 9,166,352 issued to Hansen. In
such case,
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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.
100081 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, 108. 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.
100091 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. Patent No.
9,166,352 issued
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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.
100101 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.
100111 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. I.
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.
100121 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.
100131 Fig. 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
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Fig. 7B, by using a pump 10 with a smaller outer diameter and/or less length,
the pump
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).
[0014] 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, Texas, 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.
100151 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 I0A3 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
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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.
[0016] 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.
[0017] 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
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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).
100181 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.
100191 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.
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