Note: Descriptions are shown in the official language in which they were submitted.
PLUNGER LIFT ASSEMBLY
FIELD
[0001] The present disclosure relates to artificial lift systems, and
related apparatuses, for use
in producing hydrocarbon-bearing reservoirs, and associated methods of
manipulating such
apparatuses and systems, and, in particular, to plunger lift systems and
methods of using such
systems.
BACKGROUND
[0002] Gas interference is a problem encountered while producing wells,
especially wells
with horizontal sections. In producing reservoir fluids containing a
significant fraction of
gaseous material, the presence of such gaseous material hinders production by
contributing to
sluggish flow. When plunger lift is required for assisting with production of
reservoirs using
horizontal wells, slugging of liquid, being supplied for lifting the plunger,
can also impede
production.
SUMMARY
[0003] In one aspect, there is provided a reservoir fluid production
assembly comprising:
a reservoir fluid inlet for receiving reservoir fluid flow from a downhole
wellbore space
of the wellbore;
a downhole fluid conductor for conducting the received reservoir fluid flow;
a flow diverter fluidly coupled to the downhole fluid conductor such that the
flow
diverter receives reservoir fluid flow being conducted by the downhole fluid
conductor, and
including:
a reservoir fluid discharge communicator for discharging the received
reservoir
fluid into an uphole wellbore space of the wellbore with effect that depletion
of gaseous
material, from the received reservoir fluid, is effected by separation of the
gaseous
material from the reservoir fluid within the wellbore fluid conductor, in
response to at
least buoyancy forces, such that a gaseous material-depleted reservoir fluid
is obtained
CAN_DMS \107533110\1 1
CA 2970569 2017-06-13
while displacement of the reservoir fluid from the subterranean formation is
being
effected such that the reservoir fluid is being received by the conductor
inlet and
conducted to the reservoir fluid discharge communicator via the reservoir
fluid receiver;
a gas-depleted reservoir fluid receiver for receiving the obtained gas-
depleted
reservoir fluid and conducting the gas-depleted reservoir fluid to a gas-
depleted reservoir
fluid discharge communicator;
a sealed interface within the wellbore, between: (a) the uphole wellbore space
of the wellbore,
and (b) the downhole wellbore space of the wellbore, for preventing, or
substantially preventing,
bypassing of the gas-depleted reservoir fluid receiver by the gas-depleted
reservoir fluid;
an uphole fluid conductor for conducting liquid reservoir fluid to the
produced liquid reservoir
fluid outlet, and including a liquid accumulator that is fluidly coupled to
the gas-depleted
reservoir fluid discharge communicator for accumulating of liquid reservoir
fluid of the gas-
depleted reservoir fluid that is discharged from the gas-depleted reservoir
fluid discharge
communicator;
a produced liquid reservoir fluid outlet; and
a plunger disposed within the uphole fluid conductor, uphole relative to the
gas-depleted
reservoir fluid discharge communicator of the flow diverter, and displaceable
within the uphole
fluid conductor between a downhole position and an uphole position;
wherein:
the plunger and the produced gas-depleted reservoir fluid outlet are co-
operatively
configured such that, while uphole-disposed liquid reservoir fluid is disposed
uphole of the
plunger, displacement of the plunger, from the downhole position to the uphole
position, by
pressurized gaseous material is with effect that the uphole-disposed liquid
reservoir fluid is
displaced uphole by the plunger and discharged through the produced liquid
reservoir fluid
outlet; and
the plunger is configured for being conducted through liquid reservoir fluid
that has
accumulated within the liquid accumulator, while being displaced from the
uphole position to the
CAN_DMS \107533110\1 2
CA 2970569 2017-06-13
downhole position by gravitational force in the absence of gaseous material
that is sufficiently
pressurized to counterbalance the gravitational force, such that, after the
plunger has passed
through the accumulated liquid reservoir fluid, at least a fraction of the
accumulated liquid
reservoir fluid becomes disposed uphole relative to the plunger such that the
uphole-disposed
liquid reservoir fluid is obtained.
[0004] In another aspect a reservoir fluid production system is provided
comprising the
assembly described above, wherein the assembly is disposed within a wellbore.
BRIEF DESCRIPTION OF DRAWINGS
[0005] The preferred embodiments will now be described with reference to
the following
accompanying drawings:
[0006] Figure 1 is a schematic illustration of an embodiment of a system
including a
reservoir fluid production assembly disposed within a wellbore, wih the
plunger removed for
clarity;
[0007] Figure 2 is a schematic illustration of an embodiment of a flow
diverter of the system
illustrated in Figure 1;
[0008] Figure 3 is a schematic illustration of the system illustrated in
Figure 1, with the
plunger disposed in the downhole position; and
[0009] Figure 4 is a schematic illustration of the system illustrated in
Figure 1, with the
plunger disposed in the uphole position.
DETAILED DESCRIPTION
[0010] As used herein, the terms "up", "upward", "upper", or "uphole",
mean,
relativistically, in closer proximity to the surface 106 and further away from
the bottom of the
wellbore, when measured along the longitudinal axis of the wellbore 102. The
terms -down",
"downward", "lower", or "downhole" mean, relativistically, further away from
the surface 106
and in closer proximity to the bottom of the wellbore 102, when measured along
the longitudinal
axis of the wellbore 102.
CAN_DMS \107533110\1 3
CA 2970569 2017-06-13
[0011] Referring to Figure 1, there are provided systems 8, with associated
apparatuses, for
producing hydrocarbons from a reservoir, such as an oil reservoir, within a
subterranean
formation 100, when reservoir pressure within the oil reservoir is
insufficient to conduct
hydrocarbons to the surface 106 through a wellbore 102.
[0012] The wellbore 102 can be straight, curved, or branched. The wellbore
102 can have
various wellbore portions. A wellbore portion is an axial length of a wellbore
102. A wellbore
portion can be characterized as "vertical" or "horizontal" even though the
actual axial orientation
can vary from true vertical or true horizontal, and even though the axial path
can tend to
"corkscrew" or otherwise vary. The term "horizontal", when used to describe a
wellbore
portion, refers to a horizontal or highly deviated wellbore portion as
understood in the art, such
as, for example, a wellbore portion having a longitudinal axis that is between
70 and 110 degrees
from vertical.
[0013] "Reservoir fluid" is fluid that is contained within an oil
reservoir. Reservoir fluid
may be liquid material, gaseous material, or a mixture of liquid material and
gaseous material.
In some embodiments, for example, the reservoir fluid includes water and
hydrocarbons, such as
oil, natural gas condensates, or any combination thereof.
[0014] Fluids may be injected into the oil reservoir through the wellbore
to effect stimulation
of the reservoir fluid. For example, such fluid injection is effected during
hydraulic fracturing,
water flooding, water disposal, gas floods, gas disposal (including carbon
dioxide sequestration),
steam-assisted gravity drainage ("SAGD") or cyclic steam stimulation ("CSS").
In some
embodiments, for example, the same wellbore is utilized for both stimulation
and production
operations, such as for hydraulically fractured formations or for formations
subjected to CSS. In
some embodiments, for example, different wellbores are used, such as for
formations subjected
to SAGD, or formations subjected to waterflooding.
[0015] A wellbore string 113 is employed within the wellbore 102 for
stabilizing the
subterranean formation 100. In some embodiments, for example, the wellbore
string 113 also
contributes to effecting fluidic isolation of one zone within the subterranean
formation from
another zone within the subterranean formation.
CAN_DMS \107533110\1 4
CA 2970569 2017-06-13
[0016] The fluid productive portion of the wellbore 102 may be completed
either as a cased-
hole completion or an open-hole completion.
[0017] A cased-hole completion involves running wellbore casing down into
the wellbore
through the production zone. In this respect, in the cased-hole completion,
the wellbore string
113 includes wellbore casing.
[0018] The annular region between the deployed wellbore casing and the oil
reservoir may
be filled with cement for effecting zonal isolation (see below). The cement is
disposed between
the wellbore casing and the oil reservoir for the purpose of effecting
isolation, or substantial
isolation, of one or more zones of the oil reservoir from fluids disposed in
another zone of the oil
reservoir. Such fluids include reservoir fluid being produced from another
zone of the oil
reservoir (in some embodiments, for example, such reservoir fluid being flowed
through a
production tubing string disposed within and extending through the wellbore
casing to the
surface), or injected fluids such as water, gas (including carbon dioxide), or
stimulations fluids
such as fracturing fluid or acid. In this respect, in some embodiments, for
example, the cement is
provided for effecting sealing, or substantial sealing, of flow communication
between one or
more zones of the oil reservoir and one or more others zones of the oil
reservoir (for example,
such as a zone that is being produced). By effecting the sealing, or
substantial sealing, of such
flow communication, isolation, or substantial isolation, of one or more zones
of the oil reservoir,
from another subterranean zone (such as a producing formation), is achieved.
Such isolation or
substantial isolation is desirable, for example, for mitigating contamination
of a water table
within the oil reservoir by the reservoir fluid (e.g. oil, gas, salt water, or
combinations thereof)
being produced, or the above-described injected fluids.
[0019] In some embodiments, for example, the cement is disposed as a sheath
within an
annular region between the wellbore casing and the oil reservoir. In some
embodiments, for
example, the cement is bonded to both of the production casing and the oil
reservoir.
[0020] In some embodiments, for example, the cement also provides one or
more of the
following functions: (a) strengthens and reinforces the structural integrity
of the wellbore, (b)
prevents, or substantially prevents, produced reservoir fluid of one zone from
being diluted by
water from other zones. (c) mitigates corrosion of the wellbore casing, (d) at
least contributes to
CAN_DMS \107533110\1 5
CA 2970569 2017-06-13
the support of the wellbore casing, and e) allows for segmentation for
stimulation and fluid
inflow control purposes.
[0021] The cement is introduced to an annular region between the wellbore
casing and the oil
reservoir after the subject wellbore casing has been run into the wellbore.
This operation is
known as "cementing".
[0022] In some embodiments, for example, the wellbore casing includes one
or more casing
strings, each of which is positioned within the well bore, having one end
extending from the well
head. In some embodiments, for example, each casing string is defined by
jointed segments of
pipe. The jointed segments of pipe typically have threaded connections.
[0023] Typically, a wellbore contains multiple intervals of concentric
casing strings,
successively deployed within the previously run casing. With the exception of
a liner string,
casing strings typically run back up to the surface 106.
[0024] For wells that are used for producing reservoir fluid, few of these
actually produce
through wellbore casing. This is because producing fluids can corrode steel or
form undesirable
deposits (for example, scales, asphaltenes or paraffin waxes) and the larger
diameter can make
flow unstable. In this respect, a production string is usually installed
inside the last casing string.
The production string is provided to conduct reservoir fluid, received within
the wellbore, to the
wellhead 116. In some embodiments, for example. the annular region between the
last casing
string and the production tubing string may be sealed at the bottom by a
packer.
[0025] To facilitate flow communication between the reservoir and the
wellbore, the
wellbore casing may be perforated, or otherwise include per-existing ports
(which may be
selectively openable, such as, for example, by shifting a sleeve), to provide
a fluid passage for
enabling flow of reservoir fluid from the reservoir to the wellbore.
[0026] In some embodiments, for example, the wellbore casing is set short
of total depth.
Hanging off from the bottom of the wellbore casing, with a liner hanger or
packer, is a liner
string. The liner string can be made from the same material as the casing
string, but, unlike the
casing string, the liner string does not extend back to the wellhead 116.
Cement may be
provided within the annular region between the liner string and the oil
reservoir for effecting
CAN_DMS: \ 107533110 \ 1 6
CA 2970569 2017-06-13
zonal isolation (see below), but is not in all cases. In some embodiments, for
example, this liner
is perforated to effect flow communication between the reservoir and the
wellbore. In this
respect, in some embodiments, for example, the liner string can also be a
screen or is slotted. In
some embodiments, for example, the production tubing string may be engaged or
stung into the
liner string, thereby providing a fluid passage for conducting the produced
reservoir fluid to the
wellhead 116. In some embodiments, for example, no cemented liner is
installed, and this is
called an open hole completion or uncemented casing completion.
100271 An open-hole completion is effected by drilling down to the top of
the producing
formation, and then casing the wellbore (with a wellbore string 113). The
wellbore is then
drilled through the producing formation, and the bottom of the wellbore is
left open (i.e.
uncased), to effect flow communication between the reservoir and the wellbore.
Open-hole
completion techniques include bare foot completions, pre-drilled and pre-
slotted liners, and
open-hole sand control techniques such as stand-alone screens, open hole
gravel packs and open
hole expandable screens. Packers and casing can segment the open hole into
separate intervals
and ported subs can be used to effect flow communication between the reservoir
and the
wellbore.
100281 Referring to Figure 1, an assembly 10 is provided for effecting
production of
reservoir fluid from the reservoir 104. The assembly 10 includes a production
string 202 that is
disposed within the wellbore 102. The production string 202 includes a
production string inlet
204, a downhole fluid conductor 206, a flow diverter 600, an uphole fluid
conductor 610, and a
production string outlet 208. Referring to Figures 3 and 4, the production
string 202 also
includes a plunger 300 (such as, for example, a free piston) for assisting
production of liquid
reservoir fluid through the outlet 208 from the reservoir 104. It is
understood that the plunger
300 could be in the form of a single-piece construction, or a multi-piece
construction.
100291 As discussed above, the wellbore 102 is disposed in flow
communication (such as
through perforations provided within the installed casing or liner, or by
virtue of the open hole
configuration of the completion), or is selectively disposable into flow
communication (such as
by perforating the installed casing, or by actuating a valve to effect opening
of a port), with the
CAN_DMS \107533110\1 7
CA 2970569 2017-06-13
reservoir 104. When disposed in flow communication with the reservoir 104, the
wellbore 102 is
disposed for receiving reservoir fluid flow from the reservoir 104.
[0030]
The production string inlet 204 is for receiving, via the wellbore, the
reservoir fluid
flow from the reservoir. In this respect, the reservoir fluid flow enters the
wellbore 102, as
described above, and is then conducted to the production string inlet 204. The
production string
202 includes a downhole fluid conductor 206, disposed downhole relative to the
flow diverter
600 for conducting the reservoir fluid flow, that is being received by the
production string inlet,
such that the reservoir fluid flow, that is received by the inlet 204, is
conducted to the flow
diverter 600 via the downhole fluid conductor 206.
[0031]
It is preferable to remove at least a fraction of the gaseous material from
the reservoir
fluid flow being conducted within the production string 202, prior to the
plunger 300, in order to
mitigate gas interference. The flow diverter 600, is provided to, amongst
other things, perform
this function. In this respect, the flow diverter 600 is disposed downhole
relative to the plunger
300.
Suitable exemplary flow diverters are described in International Application
No.
PCT/CA2015/000178, published on October 1, 2015.
[0032]
In some embodiments, for example, the flow diverter 600 is configured such
that the
depletion of gaseous material from the reservoir fluid material, that is
effected while the
assembly 10 is disposed within the wellbore 102, is effected externally of the
flow diverter 600
within the wellbore 102, such as, for example, within an uphole wellbore space
108.
[0033]
The flow diverter 600 includes a reservoir fluid receiver 602 (such as, for
example, in
the form of one or more ports) for receiving the reservoir fluid (such as, for
example, in the form
of a reservoir fluid flow) that is being conducted (e.g. flowed), via the
downhole fluid conductor
206 of the production string 202, from the production string inlet 204. In
some embodiments, for
example, the downhole fluid conductor 206 extends from the inlet 204 to the
receiver 602 In
some embodiments, for example, the reservoir fluid receiver 602 includes one
or more ports.
[0034]
The flow diverter 600 also includes a reservoir fluid discharge communicator
604
(such as, for example, in the form of one or more ports) that is fluidly
coupled to the reservoir
fluid receiver 602 via a reservoir fluid-conductor 603. The reservoir fluid
conductor 603 defines
CAN_DMS \107533110\1 8
CA 2970569 2017-06-13
one or more reservoir fluid conductor passages 603A (including, for example, a
network of
passages). In some of the embodiments described below, for example, the one or
more reservoir
fluid-conducting passages 603A include the fluid passage 620A, the fluid
passage 615A, and the
fluid passage 622A. The reservoir fluid discharge communicator 604 is
configured for
discharging reservoir fluid (such as, for example, in the form of a flow) that
is received by the
reservoir fluid receiver 602 and conducted to the reservoir fluid discharge
communicator 604 via
the reservoir fluid conductor 603. In some embodiments, for example, the
reservoir fluid
discharge communicator 604 is disposed at an opposite end of the flow diverter
600 relative to
the reservoir fluid receiver 602.
[0035] The flow diverter 600 also includes a gas-depleted reservoir fluid
receiver 608 (such
as, for example, in the form of one or more ports) for receiving a gas-
depleted reservoir fluid
(such as, for example, in the form of a flow), after gaseous material has been
separated from the
reservoir fluid (for example, a reservoir fluid flow), that has been
discharged from the reservoir
fluid discharge communicator 604, in response to at least buoyancy forces. In
this respect, the
gas-depleted reservoir fluid receiver 608 and the reservoir fluid discharge
communicator 605 are
co-operatively configured such that the gas-depleted reservoir fluid receiver
608 is disposed for
receiving a gas-depleted reservoir fluid flow, after gaseous material has been
separated from the
received reservoir fluid flow that has been discharged from the reservoir
fluid discharge
communicator 604, in response to at least buoyancy forces. In some
embodiments, for example,
the reservoir fluid discharge communicator 604 is disposed at an opposite end
of the flow
diverter 600 relative to the gas-depleted reservoir fluid receiver 608.
[00361 The flow diverter 600 also includes a gas-depleted reservoir fluid
conductor 610 that
includes a gas-depleted reservoir fluid-conducting passage 610A configured for
conducting the
gas-depleted reservoir fluid (for example, a gas-depleted reservoir fluid
flow) received by the
receiver 608 to a gas-depleted reservoir fluid discharge communicator 611
(such as, for example,
in the form of one or more ports). In some embodiments, for example, the gas-
depleted reservoir
fluid discharge communicator 611 is disposed at an opposite end of the flow
diverter 600 relative
to the gas-depleted reservoir fluid receiver 608. The gas-depleted reservoir
fluid discharge
communicator 611 is for discharging gas-depleted reservoir fluid into a liquid
accumulator 210B
of the uphole fluid conductor 210.
CAN_DMS \107533110\1 9
CA 2970569 2017-06-13
[0037] The assembly 10 also includes a wellbore sealed interface effector
400 configured for
interacting with a wellbore feature for defining a wellbore sealed interface
500 within the
wellbore 102, between: (a) an uphole wellbore space 108 of the wellbore 102,
and (b) a
downhole wellbore space 110 of the wellbore 102, while the assembly 10 is
disposed within the
wellbore 102. The sealed interface 500 prevents, or substantially prevents
reservoir fluid, that is
being received by the reservoir fluid receiver 608, from being conducted from
the uphole
wellbore space 108 to the downhole wellbore space 110, thereby preventing, or
substantially
preventing, bypassing of gas-depleted reservoir fluid receiver 608 by gas-
depleted reservoir fluid
that has been separated from the reservoir fluid within the uphole wellbore
space 108.
[0038] In this respect, in some embodiments, for example, the flow diverter
600 and the
wellbore sealed interface effector 400 are co-operatively configured such
that:
the reservoir fluid is discharged from the reservoir fluid discharge
communicator 604 and
conducted into the uphole wellbore space 108, such that the received reservoir
fluid flow
becomes disposed within the uphole wellbore space 108, and, while the received
reservoir fluid
is disposed within the uphole wellbore space 108, gaseous material is
separated from the
received reservoir fluid in response to at least buoyancy forces such that the
gas-depleted
reservoir fluid is obtained and is supplied to the gas-depleted reservoir
fluid receiver 608, and the
received gas-depleted reservoir fluid is conducted from the gas-depleted
reservoir fluid receiver
608 to the liquid accumulator 210B via at least the conductor 610 and the gas-
depleted reservoir
fluid discharge communicator 611;
while: (a) the assembly 10 is disposed within the wellbore 102 and oriented
such that the
production string inlet 204 is disposed downhole relative to (such as, for
example, vertically
below) the production string outlet, and the wellbore sealed interface 500 is
defined by
interaction between the wellbore sealed interface effector 400 and a wellbore
feature; (b)
displacement of the reservoir fluid from the subterranean formation is being
effected by the such
that the reservoir fluid is being received by the inlet 204 (such as, for
example, as a reservoir
fluid flow) and conducted to the reservoir fluid discharge communicator 604
via the reservoir
fluid receiver 602.
CAN_DMS 1107533110 \ 1 10
CA 2970569 2017-06-13
[0039]
The disposition of the sealed interface 500 is such that fluid flow, across
the sealed
interface 500, is prevented, or substantially prevented. In some embodiments,
for example, the
disposition of the sealed interface 500 is such that fluid flow, across the
sealed interface 500, in a
downhole direction, from the uphole wellbore space 108 to the downhole
wellbore space 110, is
prevented, or substantially prevented. In some embodiments, for example, the
disposition of the
sealed interface 500 is such that fluid, that is being conducted in a downhole
direction within the
intermediate fluid passage 112, is directed to the gas-depleted reservoir
fluid receiver 608. In
this respect, the gas-depleted reservoir fluid, produced after the separation
of gaseous material
from the received reservoir fluid within the uphole wellbore space 108, is
directed to the gas-
depleted reservoir fluid receiver 608, and conducted to the liquid accumulator
210B via at least
the conductor 610 and the gas-depleted reservoir fluid discharge communicator
611. The gas-
depleted reservoir fluid, including a liquid reservoir fluid, collects within
the liquid accumulator
210B.
[0040]
In such embodiments, for example, the disposition of the sealed interface 500
is
effected by the combination of at least: (i) a sealed, or substantially
sealed, disposition of the
wellbore string 113 relative to a polished bore receptacle 114 (such as that
effected by a packer
240A disposed between the wellbore string 113 and the polished bore receptacle
114), and (ii) a
sealed, or substantially sealed, disposition of the downhole production string
portion 206 relative
to the polished bore receptacle 114 such that reservoir fluid flow, that is
received within the
wellbore 102 (that is lined with the wellbore string 113), is prevented, or
substantially prevented,
from bypassing the reservoir fluid receiver 602, and, as a corollary, is
directed to the reservoir
fluid receiver 602 for receiving by the reservoir fluid receiver 602.
100411
In some embodiments, for example, the sealed, or substantially sealed,
disposition of
the downhole fluid conductor 206 relative to the polished bore receptacle 114
is effected by a
latch seal assembly. A suitable latch seal assembly is a WeatherfordTM Thread-
Latch Anchor
Seal AssemblyTM.
[0042]
In some embodiments, for example, the sealed, or substantially sealed,
disposition of
the downhole fluid conductor 206 relative to the polished bore receptacle 114
is effected by one
CAN_DMS \107533110\1 11
CA 2970569 2017-06-13
or more o-rings or seal-type Chevron rings. In this respect, the sealing
interface effector 400
includes the o-rings, or includes the seal-type Chevron rings.
[00431 In some embodiments, for example, the sealed, or substantially
sealed, disposition of
the downhole fluid conductor 206 relative to the polished bore receptacle 114
is disposed in an
interference fit with the polished bore receptacle. In some of these
embodiments, for example,
the downhole fluid conductor 206 is landed or engaged or "stung" within the
polished bore
receptacle 114.
100441 The above-described disposition of the wellbore sealed interface 500
provide for
conditions which minimize solid debris accumulation in the joint between the
downhole fluid
conductor 206 and the polished bore receptacle 114 or in the joint between the
polished bore
receptacle 114 and the casing 113. By providing for conditions which minimize
solid debris
accumulation within the joint, interference to movement of the separator
relative to the liner, or
the casing, as the case may be, which could be effected by accumulated solid
debris, is mitigated.
[0045] In some embodiments, for example, the space, between: (a) the gas-
depleted reservoir
fluid receiver 608 of the flow diverter 600, and (b) the sealed interface 500,
defines a sump 700
for collection of solid particulate that is entrained within fluid being
discharged from the
reservoir fluid outlet ports 606 of the flow diverter 600, and the sump 700
has a volume of at
least 0.1 m3. In some embodiments, for example, the volume is at least 0.5 m3.
In some
embodiments, for example, the volume is at least 1.0 m3. In some embodiments,
for example,
the volume is at least 3.0 m3.
[0046] By providing for the sump 700 having the above-described volumetric
space
characteristic, and/or the above-described minimum separation distance
characteristic, a suitable
space is provided for collecting relative large volumes of solid debris, such
that interference by
the accumulated solid debris with the production of oil through the system is
mitigated. This
increases the run-time of the system before any maintenance is required. As
well, because the
solid debris is deposited over a larger area, the propensity for the collected
solid debris to
interfere with movement of the flow diverter 600 within the wellbore 102, such
as during
maintenance (for example, a workover) is reduced.
CAN_DMS \ 107533110 \ 1 12
CA 2970569 2017-06-13
[0047] Referring to Figure 1, in some embodiments, for example, the sealed
interface 500 is
disposed within a section of the wellbore 14 whose axis 14(a) is disposed at
an angle "a" of at
least 60 degrees relative to the vertical "V". In some of these embodiments,
for example, the
sealed interface 500 is disposed within a section of the wellbore whose axis
is disposed at an
angle "a" of at least 85 degrees relative to the vertical "V". In this
respect, disposing the sealed
interface 500 within a wellbore section having such wellbore inclinations
minimizes solid debris
accumulation at the sealed interface 500.
[0048] In some embodiments, for example, the wellbore 102 includes a
wellbore fluid
conductor 102, such as, for example, the wellbore string 113 (such as, for
example, the casing
113), and the flow diverter 600 and the wellbore fluid conductor are co-
operatively configured
such that, while the assembly 10 is disposed within the wellbore 102 and
oriented such that the
production string inlet 204 is disposed downhole relative to the production
string outlet 208, an
intermediate fluid passage 112 is defined within the wellbore 102, between the
flow diverter 600
and the wellbore fluid conductor 102 for effecting the flow communication
between the reservoir
fluid discharge communicator 604 and the gas-depleted reservoir fluid receiver
608. In some
embodiments, for example, the intermediate fluid passage 112 is an annular
space disposed
between the flow diverter 600 and the wellbore fluid conductor 114.
[0049] Referring to Figures 1 and 2, in some embodiments, for example,
while the assembly
is disposed within the wellbore 102, the reservoir fluid discharge
communicator 604 is
oriented such that, while the assembly 10 is disposed within the wellbore 102
and oriented such
that the production string inlet 204 is disposed downhole relative to the
production string outlet
208, a ray (see, for example ray 604A, which corresponds), that is disposed
along the central
longiudinal axis of the reservoir fluid discharge communicator, is disposed in
an uphole direction
at an acute angle of less than 30 degrees relative to the central longitudinal
axis of the wellbore
portion within which the diverter is disposed.
[0050] Again referring to Figures 1 and 2, in some embodiments, for
example, while the
assembly 10 is disposed within the wellbore 102, the reservoir fluid discharge
communicator 604
is oriented such that, while the assembly 10 is disposed within the wellbore
102 and oriented
such that the production string inlet 204 is disposed downhole relative to the
production string
CAN_DMS \107533110\1 13
CA 2970569 2017-06-13
outlet 208, a ray (see, for example ray 604A, which corresponds), that is
disposed along the
central longiudinal axis of the reservoir fluid discharge communicator 604, is
disposed in an
uphole direction at an acute angle of less than 30 degrees relative to the
vertical (which includes
disposition of the ray 6060a along a vertical axis).
[0051]
In some embodiments, for example, the uphole wellbore space 108 extends uphole
from the discharge communicator 604, between the production string 202 and the
wellbore fluid
conductor 102, to a sealed interface 800 within the wellbore to define a
gaseous material
accumulator 802 for accumulating gaseous material. In some operational
implementations, for
example, the accumulated gaseous material may be used for displacing the
plunger 300 in an
uphole direction, as described below.
[0052]
In some embodiments, for example, the minimum cross-sectional flow area of the
uphole wellbore space is greater than the maximum cross-sectional flow area of
the intermediate
fluid passage. In some embodiments, for example, the ratio of the minimum
cross-sectional flow
area of the uphole wellbore space to the maximum cross-sectional flow area of
the intermediate
fluid passage is at least 1.2, such as, for example, at least 1.3, such as,
for example, at least 1.5,
such as, for example, at least 2.
[0053]
In some embodiments, for example, the gas-depleted reservoir fluid receiver
610 is
disposed downhole relative to (such as, for example, vertically below) the
reservoir fluid
discharge communicator 604, while the assembly 10 is disposed within the
wellbore 102 and
oriented such that the production string inlet 204 is disposed downhole
relative to (such as, for
example, vertically below) the production string outlet 208.
In this respect, in some
embodiments, for example, the flow diverter 600 and the sealed interface
effector 400 are co-
operatively configured such that, while: (a) the assembly 10 is disposed
within the wellbore 102
and oriented such that the production string inlet 204 is disposed downhole
relative to (such as,
for example, vertically below) the production string outlet 208, (b) the flow
diverter 600 is
integrated into the assembly such that, while the assembly 10 is disposed
within the wellbore 102
and oriented such that the production string inlet 204 is disposed downhole
relative to (such as,
for example, vertically below) the production string outlet 208, the flow
diverter 600 is oriented
such that the gas-depleted reservoir fluid receiver 608 is disposed downhole
relative to the
CAN_DMS \107533110\1 14
CA 2970569 2017-06-13
reservoir fluid discharge communicator 604, and the wellbore sealed interface
500 is defined by
interaction between the wellbore sealed interface effector 400 and a wellbore
feature, and (c)
displacement of the reservoir fluid from the subterranean formation is being
effected such that
the reservoir fluid is being received by the inlet 204 (such as, for example,
as a reservoir fluid
flow) and conducted to the reservoir fluid discharge communicator 604:
the reservoir fluid is discharged from the reservoir fluid discharge
communicator 604 and
into the uphole wellbore space 108, such that the received reservoir fluid
becomes disposed
within the uphole wellbore space 108, and, while the received reservoir fluid
is disposed within
the uphole wellbore space 108, gaseous material is separated from the received
reservoir fluid in
response to at least buoyancy forces such that the gas-depleted reservoir
fluid is obtained, and the
gas-depleted reservoir fluid is conducted downhole to the gas-depleted
reservoir fluid receiver
608, and the gas-depleted reservoir fluid, received by the gas-depleted
reservoir fluid receiver
608, is conducted from the gas-depleted reservoir fluid receiver 608 to the
gas-depleted reservoir
fluid discharge communicator 611 via at least the conductor 610.
[0054] As above-described, the uphole fluid conductor 610 extends from the
gas-depleted
reservoir fluid discharge communicator 611 to the outlet 608 for effecting
flow communication
between the discharge communicator 611 and the outlet 608. In some
embodiments, for
example, downhole fluid conductor 206 defines a fluid passage 206A that has a
maximum cross-
sectional flow area that is less than the minimum cross-sectional flow area of
the fluid passage
210A defined by the uphole fluid conductor 210. In some embodiments, for
example, the ratio
of the maximum cross-sectional flow area of the fluid passage 206A of the
downhole fluid
conductor 206 to the minimum cross-sectional flow area of the fluid passage
208A of the uphole
fluid conductor 210 is less than 0.85, such as, for example, less than 0.75,
such as, for example,
less than 0.65, such as, for example, less than 0.5, such as, for example,
less than 0.25.
[0055] As alluded to above, the liquid accumulator 210B is fluidly coupled
to the gas-
depleted reservoir fluid discharge communicator 611 for accumulating liquid
reservoir fluid of
the gas-depleted reservoir fluid that is being discharged from the gas-
depleted reservoir fluid
discharge communicator 611.
CAN_DMS \107533110\1 15
CA 2970569 2017-06-13
[0056] Referring to Figures 3 and 4, the plunger 300 is disposed within the
uphole fluid
conductor 210, uphole relative to the gas-depleted reservoir fluid discharge
communicator 611 of
the flow diverter 600. The plunger 300 is displaceable within the uphole fluid
conductor 210
between a downhole position 212A (see Figure 3) and an uphole position 214A
(see Figure 4).
In some embodiments, for example, a downhole stop 212 is provided within the
uphole fluid
conductor 210 for limiting travel of the plunger 300 in the downhole direction
and thereby
establishing the downhole position 212A. In some embodiments, for example, the
downhole
stop 212 includes a bumper spring. In some embodiments, for example, an uphole
stop 214 is
provided within the uphole fluid conductor 210 for limiting travel of the
plunger 300 in the
uphole direction and thereby establishing the uphole position 214A. In some
embodiments, for
example, the uphole stop 214 includes a bumper spring. In some embodiments,
for example, a
lubricator assembly is provided and includes the bumper spring which, amongst
other things,
functions as the uphole stop 214. In some embodiments, for example, the
lubricator assembly
also includes a plunger catcher assembly.
[0057] The plunger 300 and the outlet 208 are co-operatively configured
such that, while
uphole-disposed liquid reservoir fluid is disposed uphole of the plunger 300,
displacement of the
plunger 300, from the downhole position to the uphole position, by pressurized
gaseous material
is with effect that the uphole-disposed liquid reservoir fluid is displaced
uphole by the plunger
300 and discharged through the outlet 208. In this respect, while the plunger
300 is being
displaced uphole by the pressurized gaseous material, the moving plunger 300
displaces the
uphole-disposed liquid reservoir fluid in an uphole direction through the
uphole fluid conductor
210 to the outlet 208.
[0058] The plunger 300 is also configured for being conducted through
liquid reservoir fluid
that has accumulated within the liquid accumulator 21013, while being
displaced from the uphole
position to the downhole position by gravitational force in the absence of
gaseous material that is
sufficiently pressurized to counterbalance the gravitational force. The
downhole conduction of
the plunger 300 is such that, after the plunger 300 has passed through the
accumulated liquid
reservoir fluid, at least a fraction of the accumulated liquid reservoir fluid
becomes disposed
uphole relative to the plunger 300 such that the uphole-disposed liquid
reservoir fluid is obtained
for being displaced by the plunger 300 that is displaced by supplied
pressurized gaseous
CAN_DMS \107533110\1 16
CA 2970569 2017-06-13
material. In this respect, while the plunger 300 is being conducted downhole,
by gravity,
through the uphole fluid conductor 210, the accumulated liquid reservoir fluid
is displaced
uphole relative to the plunger 300 and becomes disposed uphole relative to the
plunger 300 as
uphole-disposed liquid reservoir fluid.
[0059] In this respect, in some embodiments, for example, the plunger 300
and the uphole
fluid conductor 210 are co-operatively configured such that spacing between
the plunger 300 and
the uphole fluid conductor 210 are sufficiently small such that the uphole-
disposed liquid
reservoir fluid does not, or does not appreciably, fall back downhole relative
to the plunger 300
(for example, because the gaseous material being flowed in an uphole direction
prevents, or
substantially prevents, such egress of the uphole-disposed liquid reservoir
fluid.
[0060] Alternatively, in some embodiments, for example, the plunger 300
includes a
selectively openable fluid passage, extending therethrough, for permitting the
accumulated liquid
reservoir fluid to be conducted through the plunger 300, as the plunger 300 is
being conducted
downhole through the accumulated liquid reservoir fluid, and also includes a
one-way valve,
such as, for example, a check valve, for preventing, or substantially
preventing such liquid
reservoir fluid, once disposed uphole relative to the plunger 300, from
returning downhole
relative to the plunger 300.
100611 As alluded to above, in some embodiments, for example, the
pressurized gaseous
material, communicated to the plunger 300, and displacing the plunger from the
downhole
position to the uphole position, originates from the gaseous material
accumulator 802. Gaseous
material being received within the uphole wellbore portion 108 accumulates
within the gaseous
material accumulator 802 such that the accumulated gaseous material becomes
disposed at a
pressure sufficient to effect the uphole displacement of the plunger 300, and,
in response, the
plunger 300 is displaced uphole. To prevent, or substantially prevent, the
accumulated gaseous
material from bypassing the plunger 300, a one-way valve 302, such as, for
example, a check
valve, is provided downhole of the flow diverter within the downhole fluid
conductor 206.
[0062] Alternatively, in some embodiments, for example, the pressurized
gaseous material is
provided from an independent source 806. In this respect, in some embodiments,
for example, a
valve 804 is provided for controlling supply of pressurized gaseous material
into the uphole fluid
CAN_DMS \107533110\1 17
CA 2970569 2017-06-13
conductor 210 (such as, for example, via the flow diverter 600) for effecting
the uphole
displacement of the plunger 300. In some embodiments, for example, a
controller is provided for
controlling operation of the valve to effect the necessary supplying of the
pressurized gaseous
material as required. In some embodiments, for example, the pressurized
gaseous material is
supplied to the uphole fluid conductor 210 via the flow diverter 600, and the
one-way valve 302,
such as, for example, a check valve, is provided within the downhole fluid
conductor 206,
downhole of the flow diverter 600, for preventing the pressurized gaseous
material from
bypassing communication with the plunger 300.
[0063]
In some embodiments, for example, an additional one-way valve 304 is disposed
between the liquid accumulator 210B and the gas-depleted reservoir fluid
discharge
communicator 611 for preventing fall-back of liquid reservoir fluid that has
collected within the
liquid accumulator 210B.
[0064]
In some embodiments, for example, the assembly 10 is disposed within a
wellbore
102 including a vertical portion and a horizontal portion, and the plunger 300
is disposed within
the vertical portion. In this respect, by virtue of one or more features of
the flow diverter 300,
gas interference is mitigated such that it becomes possible to disposed the
plunger within the
vertical portion. In some of these embodiments, for example, the horizontal
portion has a length,
measured along a longitudinal axis of the horizontal portion, of at least 100
metres, such as, for
example, at least 250 metres, such as, for example, at least 500 metres.
[0065]
In the above description, for purposes of explanation, numerous details are
set forth in
order to provide a thorough understanding of the present disclosure. However,
it will be
apparent to one skilled in the art that these specific details are not
required in order to practice
the present disclosure.
Although certain dimensions and materials are described for
implementing the disclosed example embodiments, other suitable dimensions
and/or materials
may be used within the scope of this disclosure. All such modifications and
variations, including
all suitable current and future changes in technology, are believed to be
within the sphere and
scope of the present disclosure. All references mentioned are hereby
incorporated by reference
in their entirety.
CAN_DMS \107533110\1 18
CA 2970569 2017-06-13
