Note: Descriptions are shown in the official language in which they were submitted.
VERTICAL ACCESS THERMAL WELLHEAD
BACKGROUND
[0001] Once a resource is discovered below the surface of the earth, an
extraction
system is often installed for oil production, where a thermal wellhead and
drilling tools are
employed to access and extract the discovered resource. Such wellheads may be
located
onshore or offshore depending on the location of the resource, and may include
different
components, such as casings, hangers, valves, fluid conduits, etc., which
perform
operations relevant to extraction of the resource.
[0002] In some operations, the desired resource may be found in geologic
formations
containing a mixture of heavy and viscous oil with sand, known as oil sands or
tar sands.
The viscosity profile of the oil and sand mixture makes oil extraction
difficult, calling for
an additional technique to improve the efficiency of the extraction process.
For instance,
additional extraction techniques, such as Cyclic Steam Stimulation (CSS), may
be
employed to improve the extraction process to separate the oil from the sand
and to reduce
the viscosity of the oil prior to the extraction. In a number of extraction
systems with CSS,
steam is injected into the geologic formation containing the oil sands. The
well is then shut
for a period of time (e.g., several months) allowing the oil to be
sufficiently heated. Once
the resource is heat soaked, the well is opened such that the heated oil and
condensed steam
may be extracted.
SUMMARY
[0003] In accordance with one or more embodiments, a system may include a
wellhead
having a vertical bore, a second bore, and an angled bore. The vertical bore
and the second
bore extend parallel to a longitudinal axis of the wellhead while the angled
bore extends
from the second bore at an angle with respect to the longitudinal axis of the
wellhead. The
system further includes a production tubing string suspended from the vertical
bore and
extending into a well. The system may further include a downhole pump inside
the
production tubing and flow control devices disposed at an interval along a
tail pipe in the
well. The system may further include a liner hanging from a casing in the well
and a
shifting tool supported through the second bore. The outer diameter of the
shifting tool is
Date Recue/Date Received 2020-07-17
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larger than an inner diameter of the angled bore. The system may further
include a spool
adapter having an inclined passage, which connects the vertical bore with a
wellhead top.
The angled bore meets with the second bore at an intersection located above a
bottom
hanger.
[0004] A wellhead in accordance with one or more embodiments may include a
vertical
bore, a second bore, and an angled bore. The vertical bore and the second bore
extend
parallel to a longitudinal axis of the wellhead while the angled bore extends
from the
second bore at an angle with respect to the longitudinal axis of the wellhead.
The vertical
bore may be isolated from the second bore and the angled bore. The system may
further
include a spool adapter having an inclined passage, which may connect the
vertical bore
with a wellhead top. The angled bore meets with the second bore at an
intersection located
above a bottom hanger.
[0005] In accordance with one or more embodiments, a method of using a
system may
begin with providing a wellhead having a vertical bore, a second bore, and an
angled bore.
The wellhead may be installed at a surface of the well, and the vertical bore
may be in
fluid communication with a downhole pump. The method may further includes
removing
a coil tubing from the angled bore in the wellhead where the angled bore
intersects with
the second bore extending vertically through the wellhead. The system may
further include
inserting a downhole tool into the second bore, and the downhole pump remains
downhole
during the insertion of the downhole tool. The downhole tool may be a shifting
tool which
may be engaged with at least one flow control devices disposed in the well.
The
engagement may include adjusting the at least one of flow control devices to
achieve a
desired steam to oil ratio.
BRIEF DESCRIPTION OF DRAWINGS
[0006] The following is a description of the figures in the accompanying
drawings. In
the drawings, identical reference numbers identify similar elements or acts.
The sizes and
relative positions of elements in the drawings are not necessarily drawn to
scale. For
example, the shapes of various elements and angles are not necessarily drawn
to scale, and
some of these elements may be arbitrarily enlarged and positioned to improve
drawing
legibility.
Date Recue/Date Received 2020-07-17
3
[0007] FIG. I shows an extraction system in accordance with one or more
embodiments.
[0008] FIG. 2 shows a perspective view of a wellhead in accordance with one
or more
embodiments.
[0009] FIG. 3 shows a side view of a wellhead in accordance with one or
more
embodiments.
[0010] FIG. 4 shows a cross-sectional view of a wellhead in accordance with
one or
more embodiments.
[0011] FIG. 5 shows a top view of a wellhead in accordance with one or more
embodiments.
[0012] FIGs. 6A and 6B show a cross-sectional view of a top hanger in
accordance
with one or more embodiments.
[0013] FIG. 7 shows a cross-sectional view of a bottom hanger in accordance
with one
or more embodiments.
DETAILED DESCRIPTION
[0014] Embodiments disclosed herein relate, generally, to wellheads that
may provide
a vertical access for downhole tools while maintaining an independent access
for a
production tubing such that a downhole pump disposed inside a well remains
inside the
well.
[0015] In the following detailed description, certain specific details are
set forth in
order to provide a thorough understanding of various disclosed implementations
and
embodiments. However, one skilled in the relevant art will recognize that
implementations
and embodiments may be practiced without one or more of these specific
details, or with
other methods, components, materials, and so forth. In other instances, well
known
features or processes associated with the safety system has not been shown or
described in
detail to avoid unnecessarily obscuring descriptions of the implementations
and
embodiments.
Date Recue/Date Received 2020-07-17
4
[0016] Systems disclosed herein may include a wellhead having separate
access
conduits for a downhole pump (e.g., an electric submersible pump (ESP)), coil
tubing, and
downhole tools, where the access conduits for the downhole pump and the
downhole tools
may be oriented to provide a vertical access through the wellhead while the
access conduit
for the coil tubing may be oriented at a minimum viable angle through the
wellhead. By
providing the separate vertical access conduits through the wellhead, downhole
tools may
be run into the well without undergoing any bending and without having to pull
up a
previously run downhole pump. Downhole tools run through the wellhead may then
reach
a horizontal section of the well via tubulars (also sometimes referred to as
guide string),
which for example, guide the downhole tools to engage with other components of
the
system. Other components in accordance with one or more embodiments may
include flow
control devices used in CSS operations.
[0017] For example, wellheads according to embodiments of the present
disclosure
may be useful in the CSS operations, where multiple access points through the
wellhead
may allow for simultaneous procedures in the CSS operation. In some CSS
operations,
after a well is drilled and completed, one or more flow control devices
positioned in the
well may be manipulated using a shifting tool provided downhole through a
vertical access
point in the wellhead while a production tubing remains independent from the
access point.
Instead, the production tubing is accessed through a second vertical access
point,
maintaining an isolation between the two vertical access points.
[0018] To illustrate, FIG. 1 shows an extraction system 50 applied in a
well 110 near a
resource 100 in accordance with one or more embodiments of the present
disclosure. The
well 110 includes casings, including a surface casing 58 and an intermediate
casing 112
(and optionally additional casings), lining the wellbore wall and extending
from a wellhead
60 positioned at the surface of the well 110. A perforated liner 64 may be
hung from the
lowermost end of the casing and extend through a horizontal section of the
well 110.
[0019] In preparation for production of the resource 100, downhole tools
may be sent
downhole through a tubing string inside a guide string 118 where downhole
tools may
include equipment for monitoring well environment, borehole logging, etc.,
which are
employed for CSS operations. A plurality of flow control devices 61 positioned
along a
tail pipe 114 inside the perforated liner 64 may have a generally tubular body
surrounded
by a moveable sleeve. The tail pipe 114 may be a tubular body that runs near
the resource
Date Recue/Date Received 2020-07-17
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100 below the wellhead 60, thereby providing a conduit for the flow control
devices 61
and improving downhole hydraulic characteristics near the resource 100.
Specifically, the
flow control devices 61 may be moved to alter at least one of the amount, the
direction,
and position of fluid (e.g., steam) flowing through the flow control devices,
and the fluid
may be sent through the tail pipe 114 and out of the flow control devices 61
to penetrate
through the surrounding formation of the resource 100. The tail pipe 114 (and
connected
flow control devices 61) may be fixed within the perforated liner 64, and the
well 110 may
then be shut in for a period of time to allow the fluid to sufficiently heat
soak the resource
100.
[0020] After the heat soaking period, production of the heat soaked
resource 100 may
be initiated, where the resource 100 (and condensed fluid) may flow through
the flow
control devices 61 and into the well 110. A downhole pump 62 provided at the
end of a
production tubing string 116 may pump the fluids collected in the well through
the
production string 116 to the surface of the well 110 to be processed. The
downhole pump
in accordance with one or more embodiments may be an electronic submersible
pump.
[0021] One of the main challenges in CSS operations is to achieve a desired
Steam to
Oil Ratio (SOR), which may be, in part, controlled through the flow control
devices 61.
Placement and the number of flow control devices 61 may be determined and
controlled
in order to achieve a desired SOR. Once the flow control devices 61 are set in
place
downhole, the flow control devices 61 may be adjusted to achieve the desired
SOR. The
adjustment of the flow control devices 61 for the desired SOR often requires a
large and
rigid shifting tool to withstand a force required for the shifting operation.
For example, a
shifting tool 63 may be at least 2-3/8" in overall outer diameter and between
8 and 20 feet
in length, such that the shifting tool can withstand the force required to
shift the flow
control devices 61 (to adjust flow through the flow control device 61).
However, the
shifting tool 63 may range in size, including an overall outer diameter and
length,
depending on the operational requirements.
[0022] In conventional wellheads for CSS, a single vertical access conduit
may be
provided to access a downhole pump connected via production tubing, and an
angled
access conduit may be provided for running coil tubing. Because shifting tools
(and other
downhole tools) may not bend as coil tubing bends, the size of the angled
access conduit
may limit the allowable size of downhole tool capable of fitting there
through. If the
Date Recue/Date Received 2020-07-17
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shifting tool cannot fit into the angled access conduit, the downhole pump
(connected to
the vertical access conduit through production tubing) would need to be pulled
out of the
well to allow the shifting tool or other downhole tool to be lowered into the
well through
the single vertical access conduit. Pulling the downhole pump out of the well
to clear the
passage for the shifting tool to pass through may incur additional costs and
downtime in
the CSS operation.
[0023] According to embodiments of the present disclosure, the flow control
devices
61 may be shifted within a perforated liner 64 using a shifting tool 63
without pulling the
downhole pump 62 on the production string 116. For the adjustment, an
instrumentation
coiled tubing used to send fluid downhole may then be disconnected from the
tail pipe 114
and brought back to the surface of the well to clear a passage for the
shifting tool 63 to
pass through.
[0024] A wellhead 60 having two vertical access conduits and an angled
access conduit
for coil tubing may be used in the extraction system 50 to allow a vertical
access for a large
shifting tool without the need to pull the downhole pump 62. Thus, an
extraction system
50 in accordance with one or more embodiments may include a wellhead 60
installed on
a well with both a downhole pump 62 provided on a production string 116 and
other
downhole tools such as a shifting tool 63 to adjust one or more flow control
devices
disposed inside the well. The wellhead may include a vertical bore, an angled
bore, and a
second bore, in which the second bore provides a conduit for a shifting tool
to pass through
while maintaining an independent access for the downhole pump.
[0025] One skilled in the art would appreciate how embodiments of an
extraction
system disclosed herein would allow adjustments of the flow control devices
without
pulling a downhole pump inside the well, thereby saving operational cost and
improving
CSS operations with an efficient SOR.
[0026] A perspective view of a wellhead 70 in accordance with one or more
embodiments is shown in FIG. 2. The wellhead 70 includes a thermal spool 5,
adapters 12,
and an angled bore 53 that extends from the top of the thermal spool 5 at an
angle with
respect to the longitudinal axis of the thermal spool 5. The angled bore 53 is
an independent
bore, which may allow access for a coil tubing.
Date Recue/Date Received 2020-07-17
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[0027] FIG. 3 shows a side view of the wellhead 70 in FIG. 2 where the
wellhead
includes valves 26, 37, gaskets 27, pipe fittings 28, flanges 35, nipples 36,
and bull plugs
38 that are used to seal and control the fluid flow within the wellhead 70.
FIG. 3 further
shows a partial cross-sectional view of the wellhead 70 where a top hanger 6
and a thermal
seal 7 are disposed along an upper portion of a vertical bore 51.
[0028] To illustrate with more details, FIG. 4 shows a cross sectional view
of the
wellhead in FIG. 2, showing two separate vertical bores including a vertical
bore 51 and a
second bore 52 that both extend parallel with the longitudinal axis of the
wellhead 70 inside
the thermal spool 5. The vertical bore 51 and the second bore 52 may be housed
within a
ring gasket of the wellhead 70. A thermal spool adapter 9 may extend from the
top surface
of the thermal spool 5 and connect the thermal spool 5 with a top section 72
of the wellhead
70. The thermal spool adapter 9 may provide a conduit that is slightly
inclined as shown
in FIG. 4.
[0029] The vertical bore 51 may provide a conduit for a downhole pump to
pass
through, and suspends the downhole pump from production tubing using the top
hanger 6
and the thermal seal 7. To illustrate the suspension mechanism, FIGs. 6A and
6B show a
cross sectional view on planes AA and BB of FIG. 4, respectively. Top hanger 6
allows
the suspension of the downhole pump inside the wellbore during shifting
operations of
flow control devices.
[0030] The second bore 52 may provide a conduit for a shifting tool or
other relatively
stiff downhole tool (compared with coil tubing) to pass vertically through the
wellhead 70.
[0031] The angled bore 53 extends from the top surface of the thermal spool
5 at an
angle with respect to the longitudinal axis of the wellhead, as shown in FIG.
4. The angled
bore 53 may provide a conduit for coil tubing to pass through, and suspend the
coil tubing
at a coil tubing slip 14. The angled bore 53 may intersect with the second
bore 52 above a
bottom hanger 2. Thus, when coil tubing is run through the wellhead 70, the
coil tubing
may be inserted into the angled bore 53 and bend at the intersection with the
second bore
52 to continue through the second bore 52 and into the well.
[0032] A guide string 118 may be hung from the bottom hanger 2 and extend
into a
well. In some embodiments, the guide string 118 may extend from the bottom
hanger 2
through a vertical section of a well to heel of the well (where a horizontal
section of the
Date Recue/Date Received 2020-07-17
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well begins). The guide string 118 may provide a conduit through which coil
tubing or
downhole tools inserted in the wellhead 70 through the second bore 52 or the
angled bore
53 may be guided.
[0033] For example, in thermal well, the guide string 118 may provide an
isolated bore
from the surface of the well to a horizontal section of the thermal well. Coil
tubing along
with various downhole tools and/or instrumentation may be run through the
guide string
118 to reach the horizontal section of the well, at which point the coil
tubing may be held
in coil tubing slips 14 provided in the angled bore 53. In an operation using
a vertical or
rigid tool access, the coil tubing may be pulled out of the well and out of
the angled bore
53 to allow a vertical access for the downhole tool to be run though the
second bore 52.
After the coil tubing is pulled out and the second bore 52 is cleared, the
downhole tool
(e.g., a shifting tool) may be run through the second bore 52 without ongoing
bending to
access a lower section of the well. Once the downhole tool operation is
complete (e.g.,
adjusting flow control devices is complete), the downhole tool (e.g., shifting
tool) may be
retrieved from the well via the same second bore 52 without ongoing bending.
Coil tubing
may then be run via the angled bore 53. A downhole pump suspended from the top
hanger
6 around the vertical bore 51 may be left in the well during the entire
process of removing
coil tubing from the angled bore 53, running a downhole tool through the
second bore 52,
removing the downhole tool, and running coil tubing through the angled bore
53.
[0034] FIG. 5 shows a top view of the wellhead system in FIG. 2, where a
top section
72 is installed above the spool 5 to direct produced fluids from a well to
production lines.
FIG. 7 shows a cross-sectional view of plane CC in FIG. 4, which shows a
suspension
mechanism of the bottom hanger 2 for the shifting tool. Additional vent 40 may
be applied
at the bottom of the wellhead for additional drainage capabilities of the
wellhead.
[0035] A method of using a wellhead in accordance with one or more
embodiments
may include installing a wellhead on a well near a resource as illustrated in
FIG. 1. Once
the wellhead is installed, a coil tubing disposed inside the well may be
pulled out of an
angled bore of the wellhead until a second bore of the wellhead is cleared. A
shifting tool
may then be inserted vertically into the second bore. The shifting tool may be
moved
downhole (e.g., through a guide string) until the shifting tool is
successfully engaged with
flow control devices disposed inside the well. Once the engagement is secured,
the shifting
tool may perform shifting operations in order to achieve a desired SOR.
Date Recue/Date Received 2020-07-17
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[0036] Such shifting operations may include, for example, placing the flow
control
devices along the perforated liner at an interval, adjusting the position of a
sleeve around
a flow control device to open/close/alter a flow passage there through, and/or
activating
movement of a flow control device. The shifting tool may be pulled out through
the second
bore vertically once the shifting operation is complete. Coil tubing including
downhole
tools or instrumentation capable of fitting through the angled bore 53 may be
inserted back
below the bottom hanger, for example, to take downhole measurements or to
resume a
heating operation. A downhole pump disposed inside the wellbore may remain
inside the
wellbore while the shifting tool completes the shifting operations by passing
the shifting
tool through the second bore independent from a vertical bore for the downhole
pump. In
the same manner, coil tubing may remain inside the well (suspended from an
angled bore
in the wellhead) while a downhole pump suspended from a separate vertical bore
through
the wellhead may be replaced.
[0037] Shifting operations may enable flow control devices positioned in a
thermal
well to achieve a desired steam to oil ratio, for example, by adjusting at
least one of
arrangement, direction of fluid (e.g., steam), and amount of the fluid of the
flow control
devices. One skilled in the art would appreciate how a method disclosed herein
may
provide a cost efficient measure to perform shifting operations for a desired
steam to oil
ratio by providing independent accesses to the downhole pump and the shifting
tool.
[0038] While the disclosure has been described with respect to a limited
number of
embodiments, those skilled in the art, having the benefit of this disclosure,
will appreciate
that other embodiments can be devised that do not depart from the scope of the
disclosure
as described. Accordingly, the scope of the disclosure should be limited only
by the
accompanying claims.
Date Recue/Date Received 2020-07-17
