U.S. patent application number 16/667310 was filed with the patent office on 2020-07-02 for hydrates for well control.
The applicant listed for this patent is ExxonMobil Upstream Research Company. Invention is credited to Rachna Jain, Kaustubh S. Kulkarni, William R. Meeks, Timothy J. Nedwed.
Application Number | 20200208491 16/667310 |
Document ID | / |
Family ID | 71122637 |
Filed Date | 2020-07-02 |
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United States Patent
Application |
20200208491 |
Kind Code |
A1 |
Nedwed; Timothy J. ; et
al. |
July 2, 2020 |
Hydrates For Well Control
Abstract
Systems, apparatus, and methods for controlling a well blowout
comprising: a flow control device such as a blowout preventer on a
wellbore, the primary throughbore of the flow control device
comprising internal dimensional irregularities creating a
non-uniform flow path in the primary throughbore which as
sufficient fluid rate may enhance pressure fluid pressure drop
therein; a control fluid aperture fluidly connected with the
wellbore for introducing a control fluid through a control fluid
aperture and into the primary throughbore while wellbore fluid
flows through the wellbore; a hydrate component introduction pump
for introducing the hydrate inducing component into the control
fluid; a hydrate inducing fluid aperture positioned in the wellbore
conduit below the control fluid aperture for introducing the
hydrate inducing fluid into the wellbore and for combining with the
control fluid that includes the hydrate inducing fluid to form a
saturated hydrate forming fluid mixture within the primary
throughbore while control fluid is also being introduced into the
wellbore through the control fluid aperture.
Inventors: |
Nedwed; Timothy J.;
(Houston, TX) ; Meeks; William R.; (Midland,
TX) ; Jain; Rachna; (Collierville, TN) ;
Kulkarni; Kaustubh S.; (Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Upstream Research Company |
Spring |
TX |
US |
|
|
Family ID: |
71122637 |
Appl. No.: |
16/667310 |
Filed: |
October 29, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62786870 |
Dec 31, 2018 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/06 20130101;
E21B 33/068 20130101; E21B 41/0021 20130101 |
International
Class: |
E21B 33/068 20060101
E21B033/068; E21B 41/00 20060101 E21B041/00; E21B 33/06 20060101
E21B033/06 |
Claims
1. A method of performing a wellbore intervention operation to
reduce an uncontrolled flow of wellbore fluids from a subterranean
wellbore, the method comprising: providing a flow control device,
the flow control device engaged proximate a top end of a wellbore
conduit that includes a wellbore throughbore, the flow control
device including a primary throughbore coaxially aligned with and
included within the wellbore throughbore; providing a control fluid
aperture proximate the top end of the wellbore conduit, the control
fluid aperture being fluidly connected with the primary
throughbore; providing a hydrate inducing fluid aperture in the
wellbore throughbore at an upstream location in the wellbore
throughbore with respect to the control fluid aperture and with
respect to the direction of wellbore blowout fluid flow through the
wellbore throughbore; introducing a control fluid through the
control fluid aperture and into the wellbore throughbore while the
wellbore blowout fluid flows at an uncontrolled rate from the
subterranean formation and through the wellbore throughbore at a
wellbore blowout fluid flow rate, whereby the control fluid is
introduced into the wellbore throughbore at a control fluid
introduction rate that is at least 25% of the wellbore blowout
fluid flow rate from the wellbore throughbore prior to introducing
the control fluid into the wellbore throughbore; and introducing a
hydrate inducing fluid through the hydrate inducing fluid aperture
and into the wellbore throughbore while simultaneously introducing
the control fluid through the control fluid aperture at the control
fluid introduction rate to induce the formation and deposition of
hydrates within the wellbore and affect the flow rate of the
wellbore blowout fluid flow rate from the wellbore throughbore.
2. The method of claim 1, wherein the flow control device comprises
at least one of a drilling spool, a blowout preventer, a lower
marine riser package, and a riser assembly.
3. The method of claim 1, comprising providing the control fluid
aperture in or upstream of the well control device and providing
the hydrate inducing fluid aperture in another wellbore component
upstream from the well control device with respect to the direction
of flow of wellbore blowout fluid flowing through the wellbore
throughbore.
4. The method of claim 1, further comprising introducing the
control fluid into the primary throughbore at a control fluid
introduction rate of at least 50% of the wellbore blowout fluid
flow rate prior to introduction of the control fluid into the
wellbore throughbore.
5. The method of claim 1, further comprising introducing the
control fluid into the primary throughbore at a control fluid
introduction rate of at least 100% of the wellbore blowout fluid
flow rate prior to introduction of the control fluid into the
wellbore throughbore.
6. The method of claim 1, further comprising introducing the
control fluid into the primary throughbore at a control fluid
introduction rate of at least 200% of the wellbore blowout fluid
flow rate prior to introduction of the control fluid into the
wellbore throughbore.
7. The method of claim 1, further comprising using seawater for
control fluid.
8. The method of claim 1, further comprising introducing the
hydrate inducing fluid through the hydrate inducing fluid aperture
and into the wellbore throughbore when an estimated or determined
at least 25% by volume of total fluid flowing through the primary
throughbore during introduction of the control fluid into the
primary throughbore is control fluid.
9. The method of claim 1, further comprising creating hydrate
formation within the wellbore throughbore with the control
fluid.
10. The method of claim 9, wherein the hydrate inducing fluid
comprises at least one of an alkane and water further comprising
introducing carbon dioxide into the control fluid to create
hydrates within the wellbore throughbore.
11. The method of claim 1, further comprising introducing control
fluid into the wellbore throughbore at a control fluid introduction
rate sufficient to reduce the wellbore blowout fluid flow rate by
25% with respect to the wellbore blowout fluid flow rate through
the wellbore throughbore prior to introduction of the control fluid
into the wellbore throughbore.
12. The method of claim 1, further comprising introducing control
fluid into the wellbore throughbore at a control fluid introduction
rate sufficient to reduce the wellbore blowout fluid flow rate by
at least 50% with respect to the wellbore blowout fluid flow rate
through the wellbore throughbore prior to introduction of the
control fluid into the wellbore throughbore.
13. The method of claim 1, further comprising introducing control
fluid into the wellbore throughbore at a control fluid introduction
rate sufficient to reduce the wellbore blowout fluid flow rate by
at least 75% with respect to the wellbore blowout fluid flow rate
through the wellbore throughbore prior to introduction of the
control fluid into the wellbore throughbore.
14. The method of claim 1, further comprising introducing control
fluid into the wellbore throughbore at a control fluid introduction
rate sufficient to reduce the wellbore blowout fluid flow rate by
at least 90% with respect to the wellbore blowout fluid flow rate
through the wellbore throughbore prior to introduction of the
control fluid into the wellbore throughbore.
15. The method of claim 1, further comprising providing the control
fluid aperture in at least one of (i) the flow control device, and
(ii) a location intermediate the flow control device and the
wellbore conduit.
16. The method of claim 1, further comprising thereafter
introducing hydrate inducing fluid through the control fluid
aperture.
17. An apparatus for performing a wellbore intervention operation
to reduce an uncontrolled flow rate of wellbore fluids from a
subterranean wellbore, the apparatus comprising: a flow control
device, the flow control device engaged proximate a top end of a
wellbore conduit that includes a wellbore throughbore at a surface
location of the wellbore conduit, the flow control device including
a primary throughbore that includes the wellbore throughbore, the
primary throughbore coaxially aligned with the wellbore
throughbore; a control fluid aperture proximate the top end of the
wellbore conduit, the control fluid aperture being fluidly
connected with the wellbore throughbore, the control fluid aperture
positioned to introduce a control fluid into the primary
throughbore concurrent with wellbore blowout fluid flowing from the
subterranean formation at an uncontrolled rate through the wellbore
throughbore at a wellbore fluid flow rate; a hydrate inducing fluid
aperture in the wellbore throughbore positioned at an upstream
location in the wellbore throughbore with respect to the control
fluid aperture and with respect to direction of flow of wellbore
blowout fluid flowing through the wellbore throughbore, the hydrate
inducing fluid aperture capable to introduce a hydrate inducing
fluid into the wellbore throughbore while the control fluid is
introduced into the wellbore throughbore through the control fluid
aperture at the control fluid introduction rate.
18. The apparatus of claim 17, wherein the flow control apparatus
comprises at least one of a blowout preventer, lower marine riser
package, at least a portion of a riser assembly, production tree,
drilling spool, and combinations thereof.
19. The apparatus of claim 17, wherein the control fluid aperture
is fluidly connected with a control fluid conduit and a control
fluid pump.
20. The apparatus of claim 17, further comprising sizing the
control fluid aperture to introduce a control fluid into the
wellbore throughbore at a control fluid introduction rate of at
least 25% of an estimated or determined wellbore blowout fluid flow
rate through the wellbore throughbore that was estimated or
determined prior to introduction of the control fluid into the
wellbore throughbore.
21. The apparatus of claim 19, wherein the control fluid pump and
control fluid conduit are capable of introducing control fluid
through the control fluid aperture and into the wellbore
throughbore at a control fluid introduction rate of at least 50% of
the wellbore blowout fluid flow rate through the wellbore
throughbore prior to introduction of the control fluid into the
wellbore throughbore.
22. The apparatus of claim 19, wherein the control fluid pump and
control fluid conduit are capable of introducing control fluid
through the control fluid aperture and into the wellbore
throughbore at a control fluid introduction rate of at least 100%
of the wellbore blowout fluid flow rate through the wellbore
throughbore prior to introduction of the control fluid into the
wellbore throughbore.
23. The apparatus of claim 19, wherein the control fluid pump and
control fluid conduit are capable of introducing control fluid
through the control fluid aperture and into the wellbore
throughbore at a control fluid introduction rate of at least 200%
of the wellbore blowout fluid flow rate through the wellbore
throughbore prior to introduction of the control fluid into the
wellbore throughbore.
24. The apparatus of claim 17, wherein the weighted fluid aperture
is dimensioned to introduce weighted fluid into the wellbore
throughbore at a rate whereby the weighted fluid falls through the
wellbore fluid.
25. The apparatus of claim 17, wherein the hydrate inducing fluid
aperture is upstream of the nearest control fluid aperture, by at
least three internal diameters of the wellbore conduit
throughbore.
26. The apparatus of claim 17, wherein the hydrate inducing fluid
aperture is upstream of the nearest control fluid aperture, by at
least five internal diameters of the wellbore conduit
throughbore.
27. The apparatus of claim 17, wherein the control fluid comprises
at least one of seawater, freshwater, saturated brine, and a
drilling mud.
28. The apparatus of claim 27, wherein the control fluid further
comprises at least one of carbon dioxide, nitrogen, air and
combinations thereof.
29. The apparatus of claim 17, wherein the hydrate inducing fluid
comprises at least one of a seawater, saturated brine, drilling
mud, and cement.
30. The apparatus of claim 17, wherein the control fluid aperture
is located in at least one of a blowout preventer and a drilling
spool.
31. The apparatus of claim 17, further comprising a vessel remotely
located with respect to wellbore centerline, the vessel having at
least one of the control fluid pump and the hydrate inducing fluid
pump.
32. The apparatus of claim 17, wherein the hydrate inducing fluid
aperture in the wellbore throughbore is provided at an upstream
location in the wellbore throughbore with respect to the control
fluid aperture and with respect to the direction wellbore blowout
fluid flow through the wellbore throughbore.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Application 62/786,870 filed Dec. 31, 2018 entitled "Hydrates for
Well Control," the entirety of which is incorporated by reference
herein.
FIELD OF THE DISCLOSURE
[0002] The present disclosure is directed generally to apparatus,
systems, and methods for well control, such as may be useful in
relation to a hydrocarbon well blowout event and more particularly
to systems and methods pertaining to an interim intervention
operation for an out of control well.
BACKGROUND OF THE DISCLOSURE
[0003] Safety and time are of the essence in regaining control of a
well experiencing loss of wellbore pressure control. Loss of
pressure control and confinement of a well is commonly referred to
as a "blowout." Well control pressure management or "intervention"
is required to regain pressure control and confine wellbore fluids
within the formation and wellbore. Well control intervention is an
important concern not only to the oil and gas industry from a
safety and operations standpoint, but also with regard to
protecting commercial, environmental, and societal interests at
large.
[0004] Well control intervention systems and methods are generally
classified as either conventional or unconventional. Conventional
intervention systems are generally used when the well can be
shut-in or otherwise contained and controlled by the wellbore
hydrostatic head and/or surface pressure control equipment. In
contrast, unconventional well control intervention systems are
generally used to attempt to regain control of flowing wells that
cannot be controlled by the wellbore fluid and/or surface pressure
control equipment. Such "blowout" situation may result from failure
of downhole equipment, loss of wellbore hydrostatic control, and/or
failure of surface pressure-control equipment. In both intervention
classifications, the object of regaining well control is to halt
the flow of fluids (liquid and gas) from the wellbore, generally
referred to as "killing" or "isolating" the well. Unconventional
methods are more complex and challenging than conventional methods
and frequently require use of multiple attempts and/or methods,
often requiring substantial time investment, including sometimes
drilling relief wells. Improved methods and systems for
unconventional well control intervention are needed.
[0005] Unconventional well control intervention methods include
"direct" intervention, referring to intervention actions occurring
within the wellbore and indirect intervention refers to actions
occurring at least partially outside of the flowing wellbore, such
as via a relief well. Two known unconventional direct intervention
methods include a momentum weighted fluid methods and dynamic
weighted fluid methods. Momentum weighted fluid methods rely upon
introducing a relatively high density fluid at sufficient rate and
velocity, directionally oriented in opposition to the adversely
flowing well stream, so as to effect a fluid collision having
sufficient momentum that the kill fluid overcomes the adverse
momentum of the out of control fluid stream within the wellbore.
Such process is commonly referred to as "out running the well."
This is often a very difficult process, especially when performed
at or near the surface of the wellbore (e.g., "top-weighted
fluid").
[0006] Dynamic weighted fluid methods are similar to momentum
weighted fluid methods except dynamic weighted fluid methods rely
upon introduction of the weighted fluid stream into the wellbore at
a depth such that hydrostatic and hydrodynamic pressure are
combined within the wellbore at the point of introduction of the
weighted fluids into the wellbore, thereby exceeding the flowing
pressure of the blowout fluid in the wellbore and killing the well.
Dynamic weighted fluid interventions are commonly used in relief
well and underground blowout operations, but are also implemented
directly in wellbores that contain or are provided with a conduit
for introducing the weighted fluid into the wellbore relatively
deep so as to utilize both hydrostatic and hydrodynamic forces
against the flowing fluid.
[0007] However, each of the aforementioned well control procedures
require significant time to plan, deploy resources, and enact. Need
remains for yet an additional well control intervention that can be
relatively quickly implemented as compared to the other
intervention mechanisms. An efficient response system is desired to
provide interim well control intervention that at least temporarily
impedes or preferably halts the uncontrolled flow of fluids from an
out of control wellbore and provides a time cushion until a more
permanent solution can be developed and implemented.
SUMMARY OF THE DISCLOSURE
[0008] Systems, equipment, and methods are disclosed herein that
may be useful for intervention in a wellbore operation that has
experienced a loss of hydrostatic formation pressure control, such
as a blowout. The disclosed information may enable regaining some
control of the well, mitigating the flow rate of the blowout, and
potentially even wholly halt the uncontrolled fluid flow. The
disclosed technology includes creating a hydrate buildup within the
wellbore that creates an impediment or plug that prevents or
restricts the blowout fluid flow rate.
[0009] The disclosed control system may be relatively quickly
implemented as an interim intervention mechanism to restrict or
contain effluent from the wellbore so as to provide a time-cushion
until a permanent well control solution can be implemented.
Thereby, conventional and/or other unconventional well control
operations for a permanent or final solution may (subsequently or
concurrently) proceed in due course to stop or control the well
effluent flowrate.
[0010] In one aspect, the methods disclosed herein may include
systems, apparatus, and methods for controlling a well blowout
comprising; a flow control device such as a blowout preventer on a
wellbore; a control fluid aperture fluidly connected with the
wellbore for introducing a control fluid through a control fluid
aperture and into the wellbore while wellbore fluid flows from the
subterranean formation through the wellbore; a hydrate inducing
fluid aperture positioned in the wellbore conduit below the control
fluid aperture for introducing a hydrate inducing fluid into the
wellbore while control fluid is also being introduced into the
wellbore through the control fluid aperture.
[0011] In an aspect, the primary throughbore of the flow control
device comprising internal dimensional irregularities creating
increased friction through a hydro-dynamically tortuous or
non-uniform flow path in the primary throughbore, or such as drill
pipe or other tools positioned therein.
[0012] In another aspect, the processes disclosed herein may
include a method of performing a wellbore intervention operation to
reduce an uncontrolled flow of wellbore fluids from a subterranean
wellbore, the method comprising: providing a flow control device,
the flow control device engaged with a top end of a wellbore
conduit that includes a wellbore throughbore, the flow control
device including a primary throughbore that comprises at least a
portion of the wellbore throughbore, the primary throughbore being
coaxially aligned with the wellbore throughbore; providing a
control fluid aperture in at least one of (i) the top end of the
wellbore conduit, (ii) the flow control device, and (iii) a
location intermediate (i) and (ii), the control fluid aperture
being fluidly connected with the wellbore throughbore; providing a
hydrate inducing fluid aperture into the wellbore throughbore at an
upstream location in the wellbore throughbore with respect to flow
of wellbore blowout fluid flowing through the wellbore throughbore
(that is, below the control fluid aperture); introducing a control
fluid through the control fluid aperture and into the wellbore
throughbore while a wellbore blowout fluid flows from the
subterranean formation through the wellbore throughbore at a
wellbore blowout fluid flow rate, whereby the control fluid is
introduced into the wellbore throughbore at a control fluid
introduction rate that is at least 25% (by volume) of the
previously estimated or determined wellbore blowout fluid flow rate
from the wellbore throughbore prior to introducing the control
fluid into the wellbore throughbore; and introducing a hydrate
inducing fluid through the hydrate inducing fluid aperture and into
the wellbore throughbore while pumping the control fluid through
the control fluid aperture.
[0013] In yet another aspect, the advantages disclosed herein may
include an apparatus for performing a wellbore intervention
operation to reduce an uncontrolled flow rate of wellbore blowout
fluids from a subterranean wellbore, the apparatus comprising: a
flow control device, the flow control device engaged with a top end
of a wellbore conduit that includes a wellbore throughbore at a
surface location of the wellbore conduit, the flow control device
including a primary throughbore that includes the wellbore
throughbore, the primary throughbore coaxially aligned with the
wellbore throughbore; a control fluid aperture in at least one of
(i) the top end of the wellbore conduit, (ii) the flow control
device, and (iii) a location intermediate (i) and (ii), the control
fluid aperture being fluidly connected with the wellbore
throughbore, the control fluid aperture for introducing a control
fluid into the wellbore throughbore while a wellbore blowout fluid
flows from the subterranean formation through the wellbore
throughbore at a wellbore blowout fluid flow rate, whereby the
control fluid is introduced at a control fluid introduction rate of
at least 25% (by volume) of the wellbore blowout fluid flow rate
from the wellbore throughbore prior to introducing the control
fluid into the wellbore throughbore; a hydrate inducing fluid
aperture in the wellbore throughbore positioned at an upstream
location in the wellbore throughbore with respect to the control
fluid aperture and with respect to direction of flow of wellbore
fluid flowing through the wellbore throughbore, the hydrate
inducing fluid aperture capable to introduce a hydrate inducing
fluid into the wellbore throughbore while the control fluid is
introduced into the wellbore throughbore through the control fluid
aperture.
[0014] One collective objective of the presently disclosed
technology is creating a pressure drop in the flowing blowout fluid
within the primary throughbore by creating hydrodynamic conditions
therein that approach the maximum fluid conducting capacity of the
primary throughbore, by introducing control fluid therein. The
prior art teaches momentum controls and dynamic controls that also
utilize introducing fluid into the wellbore conduit 10. However,
the prior art types of intervention mechanisms typically rely upon
introducing the fluid into the wellbore conduit as close to bottom
hole source of the blowout energy as possible in order to provide
an increase hydrostatic column on the formation. That is, they
require introducing a separate conduit such as coil tubing or drill
pipe relatively deep into the wellbore to realize a hydrostatic
benefit and/or use momentum in the control fluid by vigorously
directing the control fluid directionally opposing the flow
direction of the blowout fluid in effort to overwhelm the blowout
fluid with momentum forces and eventual hydrostatic forces. Such
technique is known in using weighted drilling mud through a nozzle
against a flowing gas stream. In contrast to those prior art
methods, according to the presently claimed technology a pressure
drop is created within surface-accessible equipment such as near or
in the wellhead or related equipment, by overwhelming the flow
conduit therethrough with more fluid that the available pressure
wellbore flowing pressure therein can move through the opening,
thus creating an increase in pressure drop through the wellhead
equipment. Successful implementation of the presently disclosed
technology affords an additional method (in addition to the
previously known prior art methods) to achieve some measure of
control over the blowout fluid in the most readily accessible
points possible--within the wellhead or proximity thereto--while
using readily portable equipment and without requiring introduction
of a separate conduit or work string deep into the wellbore or
requiring removal of an obstruction or string from therein. Such
successful implementation of the presently disclose technology may
thus supplement the blowout intervention process, providing readily
responsive action plan that provides a temporary constriction on
the blowout until other methods such as momentum or dynamic kills
or addition of a capping stack can be subsequently implemented.
BRIEF DESCRIPTION OF THE DRAWING
[0015] FIG. 1 is an exemplary schematic representation of a well
control operation according to the present disclosure.
DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE
[0016] Relatively rapid access to processes and apparatus for
controlling and killing a well blowout may further benefit the
energy industry. The presently disclosed technology is believed to
provide functional improvements and/or improved range of
methodology options over previously available technology. Methods
and equipment are disclosed that may provide effective interim
control of blowout fluid flow from a wellbore such that a more
permanent well killing operation may be performed subsequently or
concurrently therewith. In many embodiments the presently disclosed
well control operation methods may be applied in conjunction with
performance of the long-term or "highly dependable" (permanent)
kill operation. In some instances, the presently disclosed interim
technology may morph seamlessly from a "control" intervention
operation into a permanent well killing operation.
[0017] Certain key elements, components, and/or features of the
disclosed technology are discussed herein with reference to FIG. 1,
which is merely a general technical illustration of some aspects of
the technology. Not all of the elements illustrated may be present
in all embodiments or aspects of the disclosed technology and other
embodiments may include varying component arrangements, omitted
components, and/or additional equipment, without departing from the
scope of the present disclosure. FIG. 1 merely provides a
simplified illustration of some of the basic components used in
drilling or servicing subterranean wells, particularly offshore
wells, in accordance with the presently disclosed well control
technology.
[0018] Generally, the presently disclosed technology involves
creating a temporary blockage or impedance of the wellbore blowout
fluid flow at the wellhead by introducing additional fluid into the
flow stream at such rate as to create an increased backpressure in
the wellhead throughbore that creates sufficient additional
pressure drop in the flow control device throughbore that overcomes
the flowing wellbore pressure of the blowout fluid flow through the
wellhead. In many embodiments, the control fluid is introduced in
proximity of an upper or top end of the wellbore, such as into the
wellhead, drilling spool, or in a lower portion of the blowout
preventer, or in adjacent equipment such as well control devices
(e.g., blowout preventers, master valves, etc.) that have an
internal arrangement of components exposed to the wellbore that
creates a relatively restrictive turbulence of control fluid and
formation fluid therein. In many aspects, the control fluid
introduction rate is sufficiently high so as to create a flowing
wellhead pressure drop within the wellhead primary throughbore
and/or related equipment due to the fluid mixing and turbulent flow
patterns therein, that exceeds the formation fluid flowing pressure
at that point of control fluid introduction into the wellbore. It
may be desired that the back pressure created by the increased
fluid flow-rate through the well control equipment substantially
inhibits, reduces, or even halts flow of the wellbore blowout fluid
from the wellbore. This hydrodynamic well control operation may be
subsequently continued while other operations to finally and
permanently control the well are performed, such as pumping a
weighted mud, cement, or another control fluid into the well. In
many aspects, the weighted fluid comprises at least one of a
seawater, saturated brine, drilling mud, and cement.
[0019] Another advantage offered by the present technology is use
of readily available and environmentally compatible water or
seawater as the introduced well control fluid. For offshore wells
or wells positioned on lakes or inland waterways, this creates
essentially a limitless source of control fluid, as the control
fluid is merely circulated through the system. For land-based
wells, a water source such as a bank of large tanks may be provided
to facilitate circulating water from the tanks, into the primary
throughbore, and back to the tanks or to another contained facility
where the water may could be processed and reused. As an additional
benefit, introducing seawater as the control fluid brings the added
benefit of fire suppression and thermal reduction in event the
effluent is on fire or has possibility of ignition.
[0020] Flow of the wellbore blowout fluid may be sufficiently
arrested or halted (controlled) when sufficient rate of control
fluid (e.g., water) is pumped into the well bore through a control
fluid aperture(s) in or below the well control device as to
increase fluid pressure in the well control device throughbore
greater than the flowing pressure of the hydrocarbon flow at the
point where the control fluid enters the wellbore. When wellbore
blowout fluid is thereby controlled, blowout flow velocity or rate
may be sufficiently halted or have such reduced upward velocity or
rate such that a heavier weighted fluid can then be introduced into
the wellbore through a weighted fluid aperture. The weighted fluid
aperture is positioned below the control fluid aperture. The
weighted fluid can then fall by gravity through the wellbore
blowout fluid in the wellbore and/or displace the blowout fluid as
the weighted fluid moves down the wellbore and begins permanently
killing the well blowout. The well controlling step of introducing
the control fluid into the wellbore may continue while the well
killing operation of introducing the weighted fluid into the
wellbore may be progressed until the blowout fluid no longer has
the ability to flow at the surface when the well controlling
operation of introducing the control fluid through the control
fluid aperture is suspended. Introducing the weighted fluid in
parallel with introducing the control fluid can continue until the
wellbore is fully hydraulically stabilized and no longer has the
ability to flow uncontrolled. A sufficiently reduced blowout fluid
velocity may permit the weighted fluid to flow into the well bore
without being ejected out of the well control device.
[0021] The presently disclosed methods and systems also have the
advantage of being remotely operable from the rig, vessel or
platform experiencing the blowout, as all operations may be
performed from a workboat or other vessel that is safely distant
from the blowout. By operating remotely from the drilling rig, the
well-control system or operation will not be impacted by failure of
the drilling rig. Further, pumping seawater into the well control
device as the control fluid, not only provides an infinite source
of control fluid, but also brings the advantage of adding
firefighting water into the fuel in the event that the hydrocarbons
are ignited after escaping onto the drilling rig. This system could
both save the rig, control the well, and if desired provide means
for introducing environmental-cleanup-aiding chemicals directly
into the blowout effluent stream.
[0022] FIG. 1 illustrates an exemplary equipment arrangement for a
well control operation according to the present disclosure, whereby
wellbore 50 is experiencing a well control event and an operation
according to the present disclosure is employed to intervene and
kill the flow of effluent from wellbore 50. In the exemplary aspect
illustrated in FIG. 1, a service vessel 72 is positioned safely
apart from or remote offset from the rig 62 or well centerline 11.
Exemplary vessel 72 may be loaded with equipment, pumps, tanks,
lines, drilling mud, cement, and/or other additives as may be
useful in the well control operation. Exemplary vessel 72 also
provides pumps 32, 42 for introducing fluids into the wellbore 50
via pump lines 34 and 44. A wellbore 50 is located within a
subterranean formation 60, whereby the wellbore is in fluid
communication with a reservoir or formation containing sufficient
formation fluid pressure to create a well control situation such as
a blowout. Top side well control or operation-related equipment is
positioned at several points along the wellbore 50 above the
surface location (such as mudline 48 or water surface 74) including
at water surface 74. Wellbore 50 is discharging the wellbore fluid
16 in an uncontrolled flow, from substantially any location
downstream (above) of the wellhead pressure control devices 20.
Wellbore fluid 16 may be escaping or discharged at substantially
any location downstream from at least a portion of the well control
surface equipment 20 or from the wellbore throughbore 12, such as
near the mudline 48, on a rig or surface vessel 62 or therebetween.
FIG. 1 illustrates the presence of a plurality of well control
devices 20, such as a blowout preventer 26 (BOP), a lower marine
riser package 52 (LMRP), and a marine riser 24. Well control
device(s) 20 is(are) engaged with the top end 18 of wellbore 50.
Wellbore 50 includes a wellbore conduit 10 defining a wellbore
throughbore 12 therein, such as a well casing string(s). The
collective components comprising the well control device 20 each
include a primary throughbore 70 substantially coaxially aligned
along a wellbore centerline 11 with the wellbore throughbore 12,
but not necessarily having the same primary throughbore internal
radial dimensions 28 as the wellbore conduit 10. The primary
throughbore 70 is irregular with respect to internal radial
dimensions 28 between various components therein, such as pipe rams
88, wipers, master valves on a christmas tree, plug profiles, and
will possess varying internal surface roughness and dimensional
variations so as to contribute to creation of turbulent fluid flow
therein that under conditions of sufficiently high flow rate may
create a substantial pressure drop therein that may impede the
combined flow rate of formation blowout fluid and control fluid
through the primary throughbore 70, thus aiding in creating enhance
backpressure on the wellbore 50, and reducing or halting effluent
16 flow.
[0023] In one general aspect, the disclosed technology includes a
method of performing a well control intervention operation to
reduce an uncontrolled flow of wellbore fluids 16 such as a blowout
from a subterranean wellbore 50. The term "blowout" is used broadly
herein to include substantially any loss of well control ability
from the surface, including catastrophic events as well as
less-notorious occurrences, related to the inability of using
surface pressure control equipment 20 to contain and control the
flow of effluent fluid 16 from within a wellbore conduit 10 into
the environment outside the well 50.
[0024] The disclosed method comprises providing at least one flow
control device 20, such as a BOP 26, LMRP 52, Christmas tree valve
arrangement, and snubbing equipment. The term "BOP" is used broadly
herein to generally refer to the totality of surface or subsea well
pressure or fluid controlling equipment present on the wellbore
that comprises at least a portion of the wellbore throughbore 12
and which is typically appended to the top end 18 of the wellbore
conduit 10 during an operation of, on, or within the well 50. The
main internal well control device 20 throughbore 70 within the flow
control devices may be referred to broadly herein as the primary
throughbore 70. The wellbore throughbore 12 includes the primary
throughbore 70. The well control device 20 is typically engaged
with a top end 18 of the wellbore conduit 10 at a surface location
of the wellbore conduit, such as at the seafloor mudline 48 (or
land surface or platform or vessel surface). The primary
throughbore 70 is coaxially aligned with the wellbore throughbore
12 and the primary throughbore 70 comprises internal dimensional
irregularities such as constrictions and discontinuities, along the
primary throughbore conduit 70 inner wall surface. These
irregularities may be due to varying positions and dimensions
related to internal components such as pipe rams, plug seats,
master valves, or other internal features that may create a
substantially discontinuous or irregular conduit path along the
axial length of the primary conduit 70.
[0025] A control fluid aperture 30 is provided in proximity to the
fluid control device 20, preferably located either in a lower half
of the fluid control device 20 or at a point in the wellbore
conduit 10 below (upstream with respect to the direction of blowout
fluid flow) the fluid control device 20, such as in a drilling
spool, a drilling choke-kill cross. The control fluid aperture 30
may include multiple of such apertures. The control fluid aperture
30 serves as a port(s) to introduce the control fluid into the
wellbore at sufficient rate, volume, and pressure to, in
combination with the formation fluid 16 or wholly alone, increase
the total fluid flow rate through the primary throughbore 70 so as
to impede or halt flow of formation fluid 16 through the wellbore
conduit below the control fluid aperture 30. The control fluid
aperture 30 may be provided in the top end 18 of the wellbore
conduit 10, meaning substantially anywhere along the wellbore
throughbore 12 above (uphole from) the bradenhead flange or
mudline, wherein the control fluid aperture is also fluidly
connected with the wellbore throughbore, or combinations thereof.
The ports may be generally provided substantially perpendicular to
the axis of the throughbore. In other aspects, the control fluid
aperture 30 may be provided in at least one of (i) the top end of
the wellbore conduit, (ii) the flow control device, and (iii) a
location intermediate (i) and (ii), the control fluid aperture
being fluidly connected with the wellbore throughbore, or
combinations thereof. Introduction of the control fluid is
introduced through the control fluid aperture 30, whereby the
introduced control fluid may fluidly overwhelm the fluid flow
through the wellbore throughbore 12 and may thereby provide
temporary suspension or sufficient reduction in flow of wellbore
blowout fluid 16 as to render the well at least temporarily
controlled or killed. Thereafter more permanent and conventional
killing operations may proceed, such as via introduction of a
hydrate inducing fluid to provide hydrostatic control and
containment of the wellbore 50.
[0026] In addition to the control fluid aperture 30, the disclosed
technology provides a hydrate inducing fluid aperture 40 for
introducing a weighted fluid into the wellbore below the control
fluid aperture 30 to provide the hydrostatic control and
containment of well effluent 16 from the wellbore 50. In some
aspects it may be preferred to locate the hydrate inducing fluid
aperture 40 in the wellbore throughbore 12 in proximity to the
mudline 48, such as near the top end 18 of the wellbore conduit 10,
or in a lower portion of the fluid control device 20 that is below
the control fluid aperture. The term "below" means an upstream
location in the wellbore throughbore with respect to direction of
flow of wellbore blowout fluid 16 flowing through the throughbore
12. In some embodiments, the control fluid aperture may be located
within a BOP body, between BOP rams, or in a drilling spool
(choke-kill spool), or combinations thereof. In some aspects, it
may be useful to provide the control fluid aperture 30 in the well
control device 20 and providing the hydrate inducing fluid aperture
in another wellbore component below (upstream with respect to the
direction of flow of wellbore fluid flowing through the wellbore
throughbore) from the well control device 20, or in both locations
to have sufficient control fluid introduction capacity.
[0027] Introducing a control fluid through the control fluid
aperture 30 into the wellbore throughbore 12 while wellbore blowout
fluid 16 flows from the subterranean formation 60 through the
wellbore throughbore 12 may in some instances provide sufficient
backpressure to both temporarily control and permanently control
the well. In the case of a relatively low-pressure wellbore (e.g.,
one having a BHP gradient of less than a seawater, kill mud, or
freshwater gradient) the control fluid alone may perform to both
temporarily control the well and with continued pumping also serve
as the weighted fluid to fill the wellbore with control fluid and
permanently kill the well. It may be advantageous to introduce at
least a portion or as much as possible of the control fluid into
the primary throughbore 20 as far upstream (low) as possible, such
as in the lower half of the BOP 26, such as below BOP mid-line 15,
without hydraulically interfering with introduction of the hydrate
inducing fluid into the hydrate inducing fluid aperture 40.
[0028] The presently disclosed technology also includes an
apparatus and system for performing a wellbore intervention
operation to reduce an uncontrolled flow rate of wellbore fluids
from a subterranean wellbore. In one embodiment, as illustrated in
exemplary FIG. 1, the apparatus or system may comprise a flow
control device 20 mechanically and fluidly engaged (directly or
including other components engaged therewith) with a top end of a
wellbore conduit (generally the wellhead at the surface or mudline,
but in proximity thereto such as in a conductor casing or other
conduit in proximity to the mudline or surface) that includes a
wellbore throughbore 12 at a surface location 48 of the wellbore
conduit, the flow control device 20 including a primary throughbore
70 that is included within the wellbore throughbore 12, the primary
throughbore 70 coaxially aligned with the wellbore throughbore 12
and the primary throughbore 70 comprising internal dimensional
irregularities. "Internal dimensional irregularities" and like
terms refers to the primary throughbore 70 having a non-uniform
effective internal conduit-forming surfaces or internal
cross-sectional area or internal diameter dimensions, along the
axial length of the primary throughbore 70 as compared with the
substantially uniform internal diameter of the wellbore conduit 10.
The internal dimensions of the primary throughbore may be less
than, greater than, or in some instances substantially the same as
the internal diameter of the wellbore conduit 10. "Internal
dimensional irregularities" variations include the internal
component positional and size variations within the various
apparatus, valves, BOP's, etc., that comprise the primary
throughbore 70 downstream from (above) the hydrate inducing fluid
introduction aperture. Such varying internal diameter variations
provide internal fluid flow-disrupting edges and shape
inconsistencies along the axial length of the primary throughbore
70 that collectively may facilitate substantial turbulent flow and
enhanced rate restriction, resulting in increased hydraulic
pressure drop along the primary throughbore 70.
[0029] The control fluid is introduced into the wellbore
throughbore in sufficient rate to create a substantial hydrodynamic
pressure drop within the primary throughbore 70, such as a pressure
drop of at least 10%, or at least 25%, or at least 50%, or at least
75%, or at least 100% from the previously estimated or determined
flowing hydraulic pressure of the wellbore blowout fluid within the
primary throughbore 70 before introduction of the control fluid
therein. It is anticipated that the control fluid may commonly need
to be introduced into the primary throughbore 12 at a control fluid
introduction rate that is at least 25%, or at least 50%, or at
least 100%, or at least 200% of the previously estimated or
determined wellbore blowout fluid 16 flow rate from the wellbore
throughbore 12 prior to introducing the control fluid into the
wellbore throughbore 12. In another aspect, it may be desired that
when substantially only, or at least a majority by volume, or at
least 25% by volume of the total fluid flowing (formation effluent
plus control fluid) through the downstream, outlet end of the
primary throughbore 70 is control fluid, then a weighted fluid such
as weighted mud, cement, weighted kill fluid, or heavy brine may be
introduced preferably through the weighted fluid aperture 40 and
into the wellbore throughbore 12 while pumping the control fluid
through the control fluid aperture 30.
[0030] There may be applications where it is desired to begin
pumping weighted fluid through the control fluid aperture, either
solely or in combination with introducing weighted fluid into the
weighted fluid aperture. In such instances such instances, the
weighted fluid may be substantially the same fluid as the control
fluid, or another weighted fluid.
[0031] When the well is killed (exhibiting either reduced flow rate
or halted flow rate of formation fluids from the reservoir or
formation 60) due to introduction of control fluid into the primary
throughbore 70, the well will still be flowing the control fluid
from the primary throughbore 70 exit. In many instances it is
preferred that the well is killed with respect to flow of formation
effluent through the primary throughbore, and substantially all of
the fluid discharging from the primary throughbore 70 is control
fluid. Thereby, wellbore blowout fluid 16 is effectively replaced
with control fluid such as seawater 80.
[0032] Introducing "neat" control fluid (without additives) into
the wellbore throughbore 12 may or may not fully contain or halt
formation fluid flow from the well 50 as desired. Some aspects of
the disclosed technology may include tailoring the control fluid.
In other aspects, it may be desirable to provide additives 86
through additive lines 84, 85 to the control fluid (or the weighted
fluid) by adding fluid-enhancing components therein, such as salts,
alcohols, surfactants, biocides, and polymers. In some embodiments,
the control fluid may comprise at least one of carbon dioxide,
nitrogen, air, methanol, another alcohol, NaCl, KCl, MgCl, another
salt, and combinations thereof.
[0033] In some operations it may be desirable to introduce fluid
streams comprising or consisting of polymerizable formulations
(broadly referred to herein as polymers, including actual polymers
or other chemically activated or reactive mass-forming combinations
of components), including polymerizable formulations that activate
or polymerize within the primary throughbore 70 to create a polymer
accumulation within the primary throughbore 70. Such polymerizable
formulations may be a multi-component chemical or polymer
formulations wherein each of the reactant components are separately
introduced into the primary throughbore 70 for mixing and (quickly)
reacting or (quickly) polymerizing therein. Such polymers may also
include chemical or polymer formulations that are water or
hydrocarbon activated compositions. The activated polymers may
accumulate or otherwise volumetrically build up within the primary
throughbore, creating a flowpath restriction, constriction, or full
blockage of the fluid flow rate through the primary throughbore 70.
Fibrous and/or granular solids such as nylons, kevlars, durable
materials, or fiberglass materials may also be concurrently
introduced for enhancing the toughness or shear strength of the
polymer accumulation within the primary throughbore 70.
[0034] In some applications, it may be useful to introduce the
control fluid into the wellbore throughbore 12 at a control fluid
introduction rate that indirectly provides other associated desired
effects, such as creating hydrates within the wellbore throughbore
12 such as by the introduction of carbon dioxide into the control
fluid. Creation of hydrates within the primary throughbore 70 may
assist with increasing the pressure drop through the primary
throughbore as hydrate formation progresses, by reducing the flow
cross-sectional area and internal surface roughness within the
primary throughbore. Conversely, at some ambient temperatures or
conditions it may be desirable to inhibit hydrate formation within
the control fluid apertures 30 or lines 34 in order to sustain
maximum flow rate therein and it may be useful to introduce a
hydrate inhibition component such as an alcohol into the control
fluid.
[0035] In some applications, it may be desirable to introduce
control fluid into the wellbore throughbore 12 at a control fluid
introduction rate sufficient to reduce the wellbore fluid flow rate
by determined amount, such as achieving a reduction of at least
10%, or 25%, or 50%, 75%, or 90%, or at least 100%, (by volume)
with respect to the wellbore blowout fluid 16 flow rate through the
wellbore throughbore 12 or primary throughbore 70, prior to
introduction of the control fluid into the primary throughbore
70.
[0036] The disclosed apparatus or system includes a control fluid
aperture 30 in at least one of (i) the top end of the wellbore
conduit, (ii) the flow control device, and (iii) a location
intermediate (i) and (ii), the control fluid aperture being fluidly
connected with the wellbore throughbore. The control fluid aperture
30 facilitates introducing (such as by pumping or by gravitational
flow) a control fluid into the wellbore throughbore 12 while a
wellbore fluid flows from the subterranean formation 60 through the
wellbore throughbore 12 at a wellbore fluid flow rate, whereby the
control fluid is introduced at a control fluid introduction rate of
at least 25% (by volume) of the estimated or determined wellbore
fluid flow rate was from the wellbore throughbore prior to
introducing the control fluid into the wellbore throughbore.
[0037] A hydrate inducing fluid aperture 40 is also provided for
introducing hydrate inducing fluid into the wellbore throughbore
12. The aperture 40 is positioned at an upstream location in the
wellbore throughbore with respect to the control fluid aperture and
with respect to direction of flow of wellbore fluid flowing through
the wellbore throughbore (e.g., the hydrate inducing fluid aperture
40 is generally positioned below the control fluid aperture 30 and
in some embodiments the hydrate inducing fluid aperture 40 may be
positioned below the fluid control device 20 or near a lower end of
the fluid control device 20. The hydrate inducing fluid aperture 40
is sized and/or provided by sufficient number of apertures 40 to be
capable to introduce a hydrate inducing fluid into the wellbore
throughbore 12 while the control fluid is introduced into the
wellbore primary throughbore 70 through the control fluid aperture
30, from a control fluid conduit line 34 and a control fluid pump
32.
[0038] "Flow control device" 20 is a broad term intended to refer
generally to the any of the pressure and/or flow control regulating
devices associated with the top end 18 of the well 50, including
equipment near a mudline 48, an earthen surface, or other water
surface, that may be used in conjunction with controlling wellbore
pressure and/or fluid flow during a well operation. The collection
of such devices may generally define the "primary throughbore"
portion of the wellbore throughbore 12. Exemplary well operations
using a flow control device include substantially any operation
that may encounter wellbore pressure or flow, such as drilling,
workover, well servicing, production, abandonment operation, and/or
a well capping operation, and exemplary equipment includes at least
one of a BOP 28, LMRP 52, at least a portion of a riser assembly, a
production tree, choke/kill spool, and combinations thereof.
[0039] The present apparatus or system also includes a control
fluid conduit 34 and a control fluid pump 32 in fluid communication
with the control fluid aperture 30. In some aspects, suction for
the pump may be drawn from a suction line 82 in fluid connection
with the adjacent water source 80, such as the ocean, a freshwater
source, large water tanks, etc. Using seawater or other readily
available fluid as the control fluid whereby the blowout effluent
is discharging into the ocean provides a substantially limitless
source of environmentally compatible control fluid. Thereby, the
limitations on control fluid introduction rate and duration are
merely mechanical issues that may be addressed or enhanced
separately (e.g., control fluid aperture size and number of
apertures available, pressure ratings, pump capacity, etc.).
Multiple apertures fluid connected with the wellbore throughbore 12
may be utilized as the control fluid apertures 30. The multiple
apertures may be located substantially anywhere within and/or
upstream of (below) the primary throughbore 70. It is preferred
that the most downstream (highest) hydrate inducing fluid aperture
40 is upstream of (below) all of the control fluid apertures 30,
with preferably at least 3 but more preferably at least 5 and even
more preferably at least 7 wellbore conduit effective internal
diameters of the wellbore blowout fluid 16 flow stream separating
the most upstream (lowest) control fluid aperture 30 from the most
downstream (highest) hydrate inducing fluid aperture 40. Stated
differently, the hydrate inducing fluid aperture 40 is upstream of
(below) the nearest control fluid aperture 30, by at least 3, 5, or
7 internal diameters of the wellbore conduit throughbore 12.
[0040] Thereby, the hydrate inducing fluid does not encounter the
majority of the mixing and turbulent hydraulic energy imposed into
the wellbore throughbore 12. It may also be preferred in some
aspects that the hydrate inducing fluid aperture is positioned
upstream (below) of the primary throughbore 70.
[0041] It may be desirable in some aspects that control fluid pump
32 and control fluid conduit 34 are capable of pumping control
fluid through the control fluid aperture(s) 30 and into the
wellbore throughbore 12 at a control fluid introduction rate of at
least 25%, or at least 50%, or at least 100%, or at least 200% (by
volume) of the wellbore fluid flow rate through the wellbore
throughbore 12 that was estimated or determined prior to
introduction of the control fluid into the wellbore throughbore 12.
The larger the total fluid flow rate through the primary
throughbore 70, the greater the hydraulic pressure drop created
therein by the combined fluid streams, and the larger the
volumetric fraction of control fluid introduced therein that
comprises the total fluid stream, the lower the volumetric fraction
of wellbore effluent 16 escaping into the environment from the
wellbore 50. It may be desirable in other aspects to introduce
sufficient control fluid into the wellbore such that the fractional
rate of wellbore effluent from the reservoir is substantially
nothing or incidental. In another aspect, it may be desirable that
an estimated or determined at least 25% by volume, or at least 50%
or at least 75% or at least 100% by volume of the total fluid
(control fluid plus formation effluent wellbore blowout fluid)
flowing through the primary throughbore during introduction of the
control fluid into the primary throughbore is control fluid. The
hydrate inducing fluid may be introduced through the hydrate
inducing fluid aperture and into the wellbore throughbore while
pumping the control fluid through the control fluid aperture.
[0042] The hydrate inducing fluid aperture 40 is positioned
preferably below the control fluid aperture 30 and the hydrate
inducing fluid aperture(s) is dimensioned to provide flow rate
capacity to introduce hydrate inducing fluid into the wellbore
throughbore at a rate whereby the weighted fluid falls through the
stagnant or reduced velocity wellbore fluid effluent flow rate
through the wellbore throughbore 12. In some applications such as
when it may be desirable introduce a high rate of hydrate inducing
fluid into the wellhead 18, it may be desirable to switch from
introducing the control fluid into the control fluid aperture to
introducing hydrate inducing fluid into the control fluid aperture,
such as while also introducing hydrate inducing fluid into the
hydrate inducing fluid aperture.
[0043] As used herein, the term "and/or" placed between a first
entity and a second entity means one of (1) the first entity, (2)
the second entity, and (3) the first entity and the second entity.
Multiple entities listed with "and/or" should be construed in the
same manner, i.e., "one or more" of the entities so conjoined.
Other entities may optionally be present other than the entities
specifically identified by the "and/or" clause, whether related or
unrelated to those entities specifically identified. Thus, as a
non-limiting example, a reference to "A and/or B," when used in
conjunction with open-ended language such as "comprising" may
refer, in one embodiment, to A only (optionally including entities
other than B); in another embodiment, to B only (optionally
including entities other than A); in yet another embodiment, to
both A and B (optionally including other entities). These entities
may refer to elements, actions, structures, steps, operations,
values, and the like.
[0044] As used herein, the phrase "at least one," in reference to a
list of one or more entities should be understood to mean at least
one entity selected from any one or more of the entity in the list
of entities, but not necessarily including at least one of each and
every entity specifically listed within the list of entities and
not excluding any combinations of entities in the list of entities.
This definition also allows that entities may optionally be present
other than the entities specifically identified within the list of
entities to which the phrase "at least one" refers, whether related
or unrelated to those entities specifically identified. Thus, as a
non-limiting example, "at least one of A and B" (or, equivalently,
"at least one of A or B," or, equivalently "at least one of A
and/or B") may refer, in one embodiment, to at least one,
optionally including more than one, A, with no B present (and
optionally including entities other than B); in another embodiment,
to at least one, optionally including more than one, B, with no A
present (and optionally including entities other than A); in yet
another embodiment, to at least one, optionally including more than
one, A, and at least one, optionally including more than one, B
(and optionally including other entities). In other words, the
phrases "at least one," "one or more," and "and/or" are open-ended
expressions that are both conjunctive and disjunctive in operation.
For example, each of the expressions "at least one of A, B and C,"
"at least one of A, B, or C," "one or more of A, B, and C," "one or
more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone,
C alone, A and B together, A and C together, B and C together, A, B
and C together, and optionally any of the above in combination with
at least one other entity.
[0045] The phrase "etc." is not limiting and is used herein merely
for convenience to illustrate to the reader that the listed
examples are not exhaustive and other members not listed may be
included. However, absence of the phrase "etc." in a list of items
or components does not mean that the provided list is exhaustive,
such that the provided list still may include other members
therein.
[0046] In the event that any patents, patent applications, or other
references are incorporated by reference herein and (1) define a
term in a manner that is inconsistent with and/or (2) are otherwise
inconsistent with, either the non-incorporated portion of the
present disclosure or any of the other incorporated references, the
non-incorporated portion of the present disclosure shall control,
and the term or incorporated disclosure therein shall only control
with respect to the reference in which the term is defined and/or
the incorporated disclosure was present originally.
[0047] As used herein the terms "adapted" and "configured" mean
that the element, component, or other subject matter is designed
and/or intended to perform a given function. Thus, the use of the
terms "adapted" and "configured" should not be construed to mean
that a given element, component, or other subject matter is simply
"capable of" performing a given function but that the element,
component, and/or other subject matter is specifically selected,
created, implemented, utilized, programmed, and/or designed for the
purpose of performing the function. It is also within the scope of
the present disclosure that elements, components, and/or other
recited subject matter that is recited as being adapted to perform
a particular function may additionally or alternatively be
described as being configured to perform that function, and vice
versa.
[0048] As used herein, the phrase, "for example," the phrase, "as
an example," and/or simply the term "example," when used with
reference to one or more components, features, details, structures,
embodiments, and/or methods according to the present disclosure,
are intended to convey that the described component, feature,
detail, structure, embodiment, and/or method is an illustrative,
non-exclusive example of components, features, details, structures,
embodiments, and/or methods according to the present disclosure.
Thus, the described component, feature, detail, structure,
embodiment, and/or method is not intended to be limiting, required,
or exclusive/exhaustive; and other components, features, details,
structures, embodiments, and/or methods, including structurally
and/or functionally similar and/or equivalent components, features,
details, structures, embodiments, and/or methods, are also within
the scope of the present disclosure.
INDUSTRIAL APPLICABILITY
[0049] The systems and methods disclosed herein are applicable to
the oil and gas industries.
[0050] It is believed that the disclosure set forth above
encompasses multiple distinct inventions with independent utility.
While each of these inventions has been disclosed in its preferred
form, the specific embodiments thereof as disclosed and illustrated
herein are not to be considered in a limiting sense as numerous
variations are possible. The subject matter of the inventions
includes all novel and non-obvious combinations and subcombinations
of the various elements, features, functions and/or properties
disclosed herein. Similarly, where the claims recite "a" or "a
first" element or the equivalent thereof, such claims should be
understood to include incorporation of one or more such elements,
neither requiring nor excluding two or more such elements.
[0051] It is believed that the following claims particularly point
out certain combinations and subcombinations that are directed to
one of the disclosed inventions and are novel and non-obvious.
Inventions embodied in other combinations and subcombinations of
features, functions, elements and/or properties may be claimed
through amendment of the present claims or presentation of new
claims in this or a related application. Such amended or new
claims, whether they are directed to a different invention or
directed to the same invention, whether different, broader,
narrower, or equal in scope to the original claims, are also
regarded as included within the subject matter of the inventions of
the present disclosure.
* * * * *