Note: Descriptions are shown in the official language in which they were submitted.
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Drill String Applications Tool
PRIORITY
This application is a PCT International filing of US Patent Application
15/908,028, filed
February 28, 2019, which is a continuation-in-part of and claims priority
under 35 USC 120
to US Patent Application 15/721,083 filed September 29, 2017 entitled "Coiled
Tubing
Applications and Measurement Tool" which is a continuation-in-part of and
claims priority to
15/465,814 filed March 22, 2017 which is a divisional of and claims priority
to US Patent
Application 14/255,763 filed April 17, 2014, and granted as US Patent
9,702,204 on July 11,
2017, both entitled "Controlled Pressure Pulser for Coiled Tubing Measurement
While
Drilling Applications".
FIELD OF DISCLOSURE
Pulses produced by the pulser create momentary axial loads on the bottom-hole
assembly
(BHA) and along the coiled-tubing string, workover string, or drill string
(All three types of
strings will further be denoted as the "string"), thus reducing friction,
pulling the string, and
enhancing extended reach (ER) within the wellbore.
The current invention includes a downhole application improvement tool that
enhances string
operations and includes an impeller herein referred to as "the Tool" that can
be used in string
operations including but not limited to intervention and completion. The Tool
creates
controlled pulses within the drilling fluid or drilling mud that travels along
the internal
portion of the string.
BACKGROUND
This invention relates to new and improved methods and devices for completion,
deepening,
fracturing, fishing, cleanout, reentering and plug milling of the wellbore.
This invention finds
particular utility in the completion of horizontal wells. Notwithstanding
previous attempts at
obtaining cost-effective and workable horizontal-well completions, there
continues to be a
need for increasing horizontal well departure to increase, for example,
unconventional shale
plays ¨ which are wells exhibiting low permeability and therefore requiring
horizontal
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laterals increasing in length to maximize reservoir contact. With increased
lateral length, the
number of zones fractured increases proportionally.
Most of these wells are fractured using the "Plug and Pert" method which
requires
perforating the stage nearest the toe of the horizontal section, fracturing
that stage and then
placing a composite plug followed by perforating the next stage. The process
is repeated
numerous times until all the required zones are stimulated. Upon completing
the fracturing
operation, the plugs are removed with a mill/bit on the end of a down-hole
impeller that is
connected to the string. As the lateral length increases, milling becomes less
efficient, leading
to the use of j ointed pipe for removing plugs.
Two related reasons cause this reduction in efficiency. First, as the depth
increases, the
effective maximum weight on bit (WOB) decreases. Second, at increased lateral
depths, the
coiled tubing is typically in a stable helical spiral in the wellbore. The
operator sending the
additional string (and weight from the surface) will have to overcome greater
static loads
leading to a longer and inconsistent transmission of load to the bit. The
onset of these two
effects is controlled by several factors including; pipe wall thickness,
wellbore deviation and
build angle, completion size, pipe/casing contact friction drag, fluid drag,
debris, and bottom
hole assembly (BHA) weight and size. Pipe or tubing with an outer diameter
less than 4
inches tends to buckle due to easier helical spiraling, thus increasing the
friction caused by
increased contact surface area along the wall of the bore hole. Outer
diameters greater than 4
inches are impractical due to weight and friction limitations. Friction drag
is a function of
pipe wall thickness and diameter, leaving end loads as one of the variables
most studied for
manipulation to achieve better well completion.
In fracturing applications, milling out frac-plugs with coiled tubing can be
challenging,
especially in longer laterals. Vibration or water hammer type of extended
reach (ER) tools
included in the BHA can extend the coiled tubing unit's reach to the deepest
plugs, but well-
site operators still encounter slow drilling, motor stalls, debris build-up
and coil lock up,
which can cause delays and require frequent short trips.
Horizontal wellbores around the world are getting longer, leading to more
demand for these
extended-reach (ER) tools. A more powerful mechanical agitation feature is
needed to carry
coiled-tubing strings to deeper total depth (TD). In coil-frac applications,
TDs are reached
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without the need to pump down annulus with frac pumps, which is operationally
complex,
and could inadvertently shift a frac sleeve.
The present disclosure relates to a tool that provides for extended lateral
reach due to reduced
friction forces as well as improved weight transfer to the BHA (bottom hole
assembly).
Improved weight transfer is a cost-effective solution for these operations. A
reduced number
of trips down hole also translate into reduced fatigue of the coil string and
extension for
further reach.
Coiled tubing string replacement is one of the highest costs for CT operators
in
unconventional well completions. Because coil life is a function of its
reeling and unreeling,
excessive coil movement can create premature fatigue and shorten the life of
the coil. The
tool described herein enables drill-outs and hole-cleaning with a minimum
number of short
trips, extending coil life and saving money for CT providers and of course
associated oil
company operators.
Pulsing technology incorporated within the tool acts to reduce friction along
the length of the
coil while also providing axial pull at the end of the string, in excess of
several thousand
pounds.
SUMMARY
The need to effectively overcome these challenges regarding lateral reach has
led to the
development of the tool and associated devices of the present disclosure. This
tool allows for
improved methods that provide better well completions, achieving extended
reach, better rate
and direction of penetration with proper WOB (weight on bit).
Current pulser technology utilizes pulsers that are sensitive to different
fluid properties,
down-hole pressures, and flow rates, and requires field adjustments to pulse
properly.
Newer technology incorporated includes the use of water hammer devices
producing a force
when the drilling fluid is suddenly stopped or interrupted by the sudden
closing of a valve.
This axial force created by the sudden closing and opening of the valve can be
used to pull
the coiled tubing deeper into the wellbore. The pull into the wellbore is
increased by the axial
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stress in the coiled tubing and straightening the tubing due to momentary
higher fluid
pressure inside the tubing and thus reducing the frictional drag. This task ¨
generating the
force by opening and closing valves - can be accomplished in many ways ¨ and
is also the
partial subject of the present disclosure.
The present disclosure and associated embodiments allow for providing a pulser
system
within string such that the pulse amplitude increases with flow rate or
overall fluid pressure
within easily achievable limits, does not require field adjustment, and is
capable of creating
recognizable, repeatable, reproducible, fluid pulse signals using minimum
power due to
unique design features. The tool utilizes turbine or impeller generated energy
to provide
controlled rate of penetration (ROP) capabilities, extended reach (ER) and
axial agitation
within the string using the tool of the present disclosure.
As indicated above, the coiled tubing industry continues to be one of the
fastest growing
segments of the oilfield services sector, and for good reason. Growth has been
driven by
attractive economics, continual advances in technology, and utilization of a
drill string to
perform an ever-growing list of field operations. The economic advantages of
the present
invention include; pulse with as much amplitude as required, extended reach of
the string to
the end of the run, allowing for reduction of time on the well and more
efficient well
production, reduced coiled tubing fatigue by eliminating or reducing string
cycling (insertion
and removal of the coil tubing string from the well), high pressure pulses
with little or no
kinking and less friction as the pulses are at least partially controlled in
this manner.
More specifically, an apparatus for generating pressure pulses in a drilling
fluid that is
flowing, enhancing, and completing a well bore within a coiled tubing assembly
comprises: a
valve longitudinally and axially positioned within the center of a main valve
assembly
including a main valve wherein the main valve assembly also comprises a main
valve
pressure chamber, and a main valve orifice with a main valve, such that the
drilling fluid
splits into both an inlet main fluid stream and a pilot fluid stream. The
pilot fluid stream
flows through a pilot flow annulus, and into a pilot inlet port, wherein the
pilot fluid then
flows past the pilot inlet cam behind the main valve activating the main
valve. The pilot fluid
flows out through a pilot outlet and recombines with a main flow then passes
around a drive
coupling mechanism toward an impeller enabling the pulser to generate
controllable, large,
rapid pulses.
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Here the upper and lower rotary seals exist within an oil filled pressure
chamber and act to
separate the pilot fluid above or in front of the upper rotary seal from a
portion exposed to
atmospheric pressure that exists below or behind the lower rotary seal so that
a drive
coupling, and gearbox, below the upper and lower rotary seals prevent pilot
fluid stream from
entering and damaging the gearbox.
Further, the pilot shaft is rotated by an impeller that converts the linear
fluid flow through the
tool into rotational motion, which is transferred from the impeller to the
gearbox via the
impeller shaft. The gearbox which is connected to the drive coupling, and
secured from
rotation by anti-rotation pins, and wherein the pilot inlet cam and the pilot
outlet cam are
positioned on the shaft so that both cams can rotate and so that when the
pilot inlet cam is in
an open position it allows the pilot fluid to enter the main valve and
simultaneously the pilot
outlet cam maintains a closed position that prevents the pilot fluid to exit
through a reverse
flow check valve.
The reverse flow check valve allows the pilot fluid stream to escape from
within the pilot
housing in normal operation but prevents fluid flow in opposite, reversed flow
direction from
the outside of the pilot housing to behind the main valve.
The resultant reverse fluid flow does not cause pulsing of fluid while
operation of pulsing
mode exists during a forward flow condition.
Further, the frequency of opening and closing of a pilot inlet cam and a pilot
outlet cam
directly influences and determines one or more frequencies of the main valve
opening and
closing to create pressure pulses in a main fluid column above or in front of
the main valve
orifice.
The impeller, through the gearbox, rotates the pilot shaft to position the
pilot inlet cam to
open and closed positions and wherein when the pilot inlet cam is a closed
position the pilot
outlet cam is in an open position the pilot fluid behind or below the main
valve to allowed
escape through the reverse flow check valve and to join the main fluid flow.
The reverse flow check valve allows pilot fluid o exit the main valve so that
the main valve
can return to a rear or open position with respect to the main valve orifice.
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The present disclosure also provides for a system that generates pressure
pulses in a drilling
fluid within a well bore that exists within a coiled tubing assembly, the
system comprising: a
tool within which exists a valve portion longitudinally and axially positioned
within a center
portion of a main valve assembly, the assembly including a main valve, a main
valve
pressure chamber, and a main valve orifice with the main valve, such that as
the drilling fluid
flows downward in the string into the Tool the drilling fluid splits into both
an inlet main
fluid stream and a pilot fluid stream, wherein the pilot fluid stream flows
through a pilot flow
.. annulus and into a pilot inlet port, wherein the pilot fluid stream then
flows into a main valve
fluid feed channel until it reaches the main valve pressure chamber and
through a pilot valve
section that functions as a pulser generating portion of the tool that further
comprises a pilot
valve housing, a pilot shaft positioned in a central axial position within the
tool supported by
thrust bearings, a seal carrier, upper and lower rotary seals, and a pilot
inlet cam and a pilot
outlet cam such that the pilot shaft can rotate said pilot inlet cam and pilot
outlet cam inside a
pilot sleeve with matching orifices so that the pilot fluid stream is
controlled by movement of
the pilot inlet cam and the pilot outlet cam and wherein the pilot fluid flows
into and
through a pilot flow outlet channel such that the pilot fluid recombines with
a main fluid
flow to become a main exit fluid flow.
In an additional embodiment, a pilot valve actuator assembly is provided. The
pilot valve
assembly is any one or more from the group consisting of; a pilot valve
housing, a pilot shaft,
rotary seals, a seal carrier, pilot cams, a pilot sleeve, oil chamber, thrust
bearings and reverse
flow check valve. Thrust bearings allow for the reduction of friction from the
impeller shaft.
Further, an impeller and impeller shaft are connected to the pilot shaft that
has pilot cams
attached to the shaft and rotate the pilot cams. The pilot cams are sized and
oriented within
the pilot sleeve in order to allow for the pilot shaft to move in a rotary
motion in order to seal
or open pilot outlet or pilot inlet port.
Rotational motion of an impeller connected to a rotating pilot shaft that is
connected to and
moves the pilot cams, causes channeling of the pilot fluid toward the main
valve. This
channeling of the fluid causes the main valve to close and also allows for the
pilot fluid to
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move the main valve. Consequently, the pilot valve cams are sized and shaped
in such a way
that part of their rotation blocks channeling of the pilot fluid toward the
main valve. This
cessation of fluid flow causes the main valve to open and also allows for the
pilot fluid to
move out of the main valve.
In this case, the apparatus generates fluid pulses such that the Tool using
the pilot shaft
rotation provides unidirectional rotary movement of the pilot shaft within the
pilot valve
housing.
Further, the apparatus provides a flow path allowing flow of the pilot fluid
through the pilot
valve that channels the pilot fluid toward the main valve resulting in
operation of the main
valve bi-directionally along the moving axis.
In an additional embodiment, differential pressure is maximized by using a
flow cone in the
main valve section. The flow cone provides for increasing the velocity of the
drilling fluid
through the orifice of the main valve section. This increase in velocity
causes an increase in
the pressure differential and also allows for utilization and better control
of the energy pulses
created by opening and closing of the main valve by using the pilot valve.
In case of no fluid flow rotating the impeller and the connected pilot cams
diverting the pilot
fluid to control the main valve, to avoid the main valve to be in a closed
stopped position a
safety mechanism prevents the main valve from staying in a closed position
allowing the
main fluid flow to start up rotating the impeller.
The tool includes three modular sections which when combined provide a
downhole tool
which measures from 1-3 feet in length depending on what main valve, pilot
valve, and
impellers are in the configuration, with an outside diameter of at least 1 and
11/16 inches.
The tool is made up in the BHA above the down-hole PDM motor during plug
milling
operations, allowing ball drop-activated tools above the tool to be operated
in the normal
fashion.
Pulses can be reliably transmitted in coil tubing strings over 30,000 ft.
In annular frac applications, the tool provides reverse circulation capability
in the event of a
screen-out. A "screen-out" is when the fracing propellant clogs the
perforation holes causing
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increased pump pressure. The operation is thus stopped in order to clean the
well bore. A
reverse flow check valve prevents the pilot valve actuating the main valve in
case the flow in
the string is reversed. The down-hole tool is compliant with the use of
hydrochloric (HC1)
and hydrofluoric (HF) acids.
In a further embodiment, the tool can be used without a reverse flow check
valve, where the
reverse flow check valve is to be replaced with a plug.
A further additional embodiment includes the use of the Tool without the pilot
outlet cam.
The present disclosure and associate inventiveness can be described as a
system that utilizes
pulse technology to improve weight transfer in horizontal wells by modulating
flow, pressure
and weight on the bit. The system can be used to overcome coiled tubing (CT)
drill out
challenges by overcoming friction forces that impede the downhole reach.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 provides a cross-sectional view of the tool.
Fig. 2 is an enlarged cross-sectional view of the main valve section.
Fig. 3A is an enlarged cross-sectional view of the pilot valve section in
relation to the main
valve section.
Fig. 3B is a more complete cross-sectional view of the pilot valve section.
Fig. 4 is an illustrated view of the power/drive section of the tool.
DETAILED DESCRIPTION OF DRAWINGS
The present disclosure and associated invention will now be described in
greater detail and
with reference to the accompanying drawings.
Figure 1 is a schematic that provides for a completed modular down-hole tool
[100] in its
entirety. The tool [100] has three major sections: the Pulser Section [101]
that houses the
main valve section [122], a pilot valve section [126], and an impeller section
[129]. The fluid
enters the tool at the top portion where the tool is connected to the coil
tubing by the upper
string connection [132] also referred to in the industry as a "top crossover
connection".
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Respectively the fluid exits the tool at the bottom through the lower string
connection [150],
also referred to in the industry as a "bottom crossover connection", where the
tool [100] is
connected to the downhole motor or some form of a Bottom Hole Assembly (BHA)
(not
shown). The fluid flows through the tool on the inside of the upper pipe
portion [120] in the
opening around the pressure housing [408] (as shown in Figure 4), and across
the impeller
[510] (as shown in Figure 5).
Figure 2 shows the main valve portion [122] of the pulser section [101]. The
fluid enters the
tool through the upper string connection [132] into the Fluid Inlet Cone [202]
and also
through the Pilot Flow Take Off ports [214] into the Pilot Flow upper Annulus
[260] to the
Pilot Flow Inlet Channel [320], bypassing the Main Valve Orifice [204]. The
Pilot Flow
upper Annulus [260] is created by the concentric Pulser Pipe [270] inside the
Upper Pipe
Portion [120] connecting the Fluid Inlet Cone [202] with the Main Valve
Housing [210].
Pilot Flow Take Off ports [214] are located along the circumferential area of
the Flow Inlet
Cone [202]. The main fluid flow in the center of the tool goes through the
Main Valve Orifice
[204] and around the Main Valve [206] in the open position, continuing around
the internal
parts of the entire Tool [100] until it exits through the Lower String
Connection [150].
The Main Valve [206] in the closed position moves upward, or forward, into the
Main Valve
Orifice [204] restricting the main fluid flow and thus creating a backpressure
in the fluid
column upstream of the Main Valve Orifice [204]. The forward closing movement
of the
Main Valve [206] is activated by the pilot fluid which enters the Main Valve
Housing [210]
through the Pilot Flow Inlet Channel [320]. The Pilot Inlet Cam [316] in the
open position
allows the pilot fluid to enter the rear part of the Main Valve [206] and the
higher pressure of
the pilot fluid causes the Main Valve [206] to move forward against the Main
Valve Orifice
[204] which is smaller in diameter with less pressure across it. The Main
Valve Plunger [208]
provides a complete seal for the pilot fluid to allow full pressure to act on
the Main Valve
[206]. When the Pilot Inlet Cam [316] closes off the incoming pilot fluid to
the rear of the
Main Valve [206], the main fluid flow through the Main Valve Orifice [204]
assisted by the
Valve Spring [207] returns the Main Valve [206] to its rear, open position
allowing the main
fluid to flow through the tool.
Figure 3A shows the Pulser Section [101] including the Main Valve Section
[122] and the
Pilot Valve Section [126] in relation to each other with their major internal
components. The
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main fluid flow enters the Tool at the top into the Fluid Inlet Cone [202] and
flows around the
Main Valve [206] and around the Pilot Valve Housing [302].
Figure 3B shows the Pilot Valve Section [126] of the Pulser Section [101]. The
main fluid
flows around the Pilot Valve Housing [302] inside the Upper Pipe Portion
[120]. The Pilot
Valve Section [126] consists of the Pilot Valve Housing [302], the Pilot Shaft
[304] which is
positioned centrally and axially located and supported by Thrust Bearings
[306], a Seal
Carrier [308], Upper and Lower Rotary Seals [310, 3111, and Pilot Inlet Cam
[316] and Pilot
Outlet Cam [314]. The Pilot Shaft [304] rotates the Pilot Inlet Cam [216] and
the Pilot Outlet
Cam [314] inside the Pilot Sleeve [318] which has matching holes to allow the
pilot fluid
flow to be controlled by the cams. The Upper and Lower Rotary Seals [310, 3111
in the Oil
Filled Chamber [326] separate the pilot fluid side above or in front of the
upper Rotary Seal
[310] from the air side below the lower Rotary Seal [311] housing the Drive
Coupling [305],
Gearbox [505] and below, thus preventing the pilot fluid from entering and
damaging the
Gearbox [505]. The Pilot Shaft [304] is rotated by the Gearbox [505] which is
connected to it
with a Drive Coupling [305]. The Pilot Inlet Cam [316] and the Pilot Outlet
Cam [314] are
positioned on the shaft rotationally so that when the Pilot Inlet Cam [316] is
in open position
it allows pilot fluid to enter the Main Valve [206]. At the same time the
Pilot Outlet Cam
[314] is in closed position preventing the fluid to exit through the Reverse
Flow Check Valve
[325]. The Impeller [507] rotates the Pilot Shaft [304] to position the Pilot
Inlet Cam [316] to
open and closed positions. When the Pilot Inlet Cam [316] is in closed
position, the Pilot
Outlet Cam [314] is in open position allowing the pilot fluid behind the Main
Valve [206] to
escape through the Reverse Flow Check Valve [325] to join the main fluid flow.
The Reverse
Flow Check Valve [325] allows the pilot fluid to exit the Main Valve [206]
thus allowing it
to return to the rear position away from the Main Valve Orifice [204]. Without
the Reverse
Flow Check Valve [325] in the case when the fluid may flow backward in the
tool, the
incoming fluid coming up from the lower part of the tool would enter the Pilot
Flow Outlet
Channel [322], which is an opening closed by a check valve, and would push the
Main Valve
[206] forward into the Main Valve Orifice [204] and thus blocking the fluid
flow in the
reverse direction through the tool. To prevent such case, the Reverse Flow
Check Valve [325]
prevents the fluid flow coming up the tool from below from entering the Pilot
Flow Outlet
Channel [322] to cause the Main Valve [206] to close to stop the fluid flow.
With the Reverse
Flow Check Valve [325] in place the tool can allow reverse fluid flow through
the tool,
although not pulsing the fluid, but still operating in normal pulsing mode in
forward flow
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condition. The frequency of opening and closing the Pilot Inlet and Pilot
Outlet Cams [316,
3141 determines the frequency of the Main Valve [206] closing and opening and
creating
pressure pulses in the main fluid column in front of the Main Valve Orifice
[204].
Figure 4 shows the Impeller section [129] of the tool located in and below the
Pressure
Housing [408] inside the upper pipe portion [120], is downstream of the Pulser
Section [101].
Fluid flows across the Impeller [510], which is mechanically connected to the
impeller shaft
[507]. The Impeller shaft is positioned centrally and axially located and
supported by Thrust
Bearings [306], a Seal Carrier [308], Rotary Seals [310], and gearbox [505].
The impeller
shaft [507] transfers rotation from the impeller [510] to the gearbox [505]
and Pilot Shaft
[304] which drives the Main Valve [206] to create positive pressure pulses in
the main fluid.
The Gearbox [505] acts to convert the rotational speed of the Impeller [510]
into the desired
rotational speed (frequency) of the Pilot Shaft [304]. Anti-rotation pins
[509] prevent the
gearbox [505] from rotating freely inside of the pressure housing [408]. A
centralizer [512]
prevents and/or limits radial motion of the pressure housing [408]. An
impeller shaft
centralizer [515] prevents and or limits radial motion of the impeller [510]
and impeller shaft
[507].
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