Note: Descriptions are shown in the official language in which they were submitted.
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Modular Design for Downhole ECD-Management Devices and
Related Methods
Field of the Invention
This invention relates generally to oilfield wellbore drilling systems and
more particularly to drilling systems that utilize active control of
bottomhole
pressure or equivalent circulating density during drilling of the wellbores.
Background of the Art
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Oilfield wellbores are drilled by rotating a drill bit conveyed into the
wellbore by a drill string. The drill string includes a drill pipe (tubing)
that has
at its bottom end a drilling assembly (also referred to as the "bottomhole
assembly" or "BHA") that carries the drill bit for drilling the wellbore. The
drill
pipe is made of jointed pipes. Alternatively, coiled tubing may be utilized to
carry the drilling of assembly. The drilling assembly usually includes a
drilling
motor or a "mud motor" that rotates the drill bit. The drilling assembly also
includes a variety of sensors for taking measurements of a variety of
drilling,
formation and BHA parameters. A suitable d rilling fluid (commonly referred to
as the "mud") is supplied or pumped under pressure from a source at the
surface down the tubing. The drilling fluid drives the mud motor a nd then
discharges at the bottom of the drill bit. Th4e drilling fluid returns uphole
via
the annulus between the drill string and the vvellbore inside and carries with
it
pieces of formation (commonly referred to as the "cuttings") cut or produced
by the drill bit in drilling the wellbore.
For drilling wellbores under water (referred to in the industry as
"offshore" or "subsea" drilling) tubing is provided at a work station (located
on
a vessel or platform). One or more tubing injectors or rigs are used to move
the tubing into and out of the wellbore. In riser-type drilling, a riser,
which is
formed by joining sections of casing or pipe, is deployed between the drilling
vessel and the wellhead equipment at the saa bottom and is utilized to guide
the tubing to the wellhead. The riser also serves as a conduit for fluid
returning from the wellhead to the sea surface.
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During drilling, the drilling operator attempts to carefully control the fluid
density at the surface so as to control pressure in the wellbore, including
the
bottomhole pressure. Typically, the operator maintains the hydrostatic
pressure of the drilling fluid in the wellbore above the formation or pore
pressure to avoid well blow-out. The density of the drilling fluid and the
fluid
flow rate largely determine the effectiveness of the drilling fluid to carry
the
cuttings to the surface. One important downhole parameter controlled during
drilling is the bottomhole pressure, which in turn controls the equivalent
circulating density ("ECD") of the fluid at the wellbore bottom.
This term, ECD, describes the condition that exists when the d rilling
mud in the well is circulated. The friction pressure caused by the fluid
circulating through the open hole and the casing(s) on its way back to the
surface, causes an increase in the pressure profile along this path that is
different from the pressure profile when the well is in a static condition
(i.e.,
not circulating). In addition to the increase in pressure while circulating,
there
is an additional increase in pressure while drilling due to the introduction
of
drill solids into the fluid. This negative effect of the increase in pressure
along
the annulus of the well is an increase of the pressure which can fracture the
formation at the shoe of the last casing. This can reduce the amount of hole
that can be drilled before having to set an additional casing. In addition,
the
rate of circulation that can be achieved is also limited. Also, due to this
circulating pressure increase, the ability to clean the hole is severely
restricted. T his condition i s exacerbated when drilling a n offshore well.
In
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offshore wells, the difference between the fracture pressures i n the shallow
sections of the well and the pore pressures of the deeper sections is
considerably smaller compared to on shore wellbores. This is due to the
seawater gradient versus the gradient that would exist if there were soil
overburden for the same depth.
In some drilling applications, it is desired to drill the wellbore at at-
balance condition or at under-balanced condition. The term at-balance
means that the pressure in the wellbore is maintained at or near the formation
pressure. The under-balanced condition means that the wellbo re pressure is
below the formation pressure. These two conditions are desirable because
the drilling fluid under such conditions does not penetrate into the
formation,
thereby leaving the formation virgin for performing formation evaluation tests
and measurements. In order to be able to drill a well to a total vvellbore
depth
at the bottomhole, ECD must be reduced or controlled. In subsea wells, one
approach is to use a mud- filled riser to form a subsea fluid circulation
system
utilizing the tubing, BHA, the annulus between the tubing a nd the wellbore
and the mud filled riser, and then inject gas (or some other low density
liquid)
in the primary drilling fluid (typically in the annulus adjacent the BHA) to
reduce the density of fluid downstream (i.e., in the remaindar of the fluid
circulation system). This so-called "dual density" approach is often referred
to
as drilling with compressible fluids.
Another method for changing the density gradient in a deepwater
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return fluid path has been proposed, but not used in practical application.
This approach proposes to use a tank, such as an elastic bag, at the sea floor
for receiving return fluid from the welibore annulus and holding it at the
hydrostatic pressure of the water at the sea floor. Independent of the flow in
the annulus, a separate return line connected to the sea floor storage tank
and a subsea lifting pump delivers the return fluid to the surface. Although
this technique (which is referred to as "dual gradient" drilling) would use a
single fluid, it would also require a discontinuity in the hydraulic gradient
line
between the sea floor storage tank and the subsea lifting pump. This requires
close monitoring and control of the pressure at the subsea storage tank,
subsea hydrostatic water pressure, subsea lifting pump operation and the
surface pump delivering drilling fluids under pressure into the tubing for
flow
downhole. The level of complexity of the required subsea instrumentation
and controls as well as the difficulty of deployment of the system has delayed
(if not altogether prevented) the practical application of the "dual gradient"
system.
Another approach is described in U.S. Patent No. 6,415,877, filed on
July 14, 1999 and assigned to the assignee of the present application. One
embodiment of this application describes a riser less system wherein a
centrifugal pump in a separate return line controls the fluid flow to the
surface
and thus the equivalent circulating density.
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The present invention provides a wellbore system wherein the
bottomhole pressure and hence the equivalent circulating density is controlled
by creating a pressure differential at a selected location in the return fluid
path
with an active pressure differential device to reduce or control the
bottomhole
pressure. The p resent system is relatively easy to i ncorporate: i n n ew and
existing systems.
SUMMARY OF THE INVENTION
The present invention provides wellbore systems for performing
downhole wellbore operations for both land and offshore wellbores. Such
drilling systems include a rig that moves an umbilical (e.g., drill string)
into and
out of the wellbore. A bottomhole assembly, carrying the drill bit, is
attached
to the bottom end of the drill string. A well control assembly or equipment on
the well receives the bottomhole assembly and the tubing. A drilling fluid
system supplies a drilling fluid into the tubing, which discharges at the
drill bit
and returns to the well control equipment carrying the drill cuttings via the
annulus between the drill string and the wellbore. A riser dispersed between
the wellhead equipment and the surface guides the drill string arn d provides
a
conduit for moving the returning fluid to the surface.
In one embodiment of the present invention, an active pressure
differential device moves in the wellbore as the drill string is maved. In an
alternative embodiment, the active differential pressure device is attached to
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the wellbore inside or wall and remains stationary relative to the wellbore
during drilling. The device is operated d uring drilling, i.e., when the
drilling
fluid is circulating through the wellbore, to create a pressure differential
across the device. This pressure differential alters the pressure on the
wellbore below or downhole of the device. The device may be controlled to
reduce the bottomhole pressure by a certain amount, to maintain the
bottomhole pressure at a certain value, or within a certain range. By severing
or restricting the flow through the device, the bottomhole pressure may be
increased.
The system also includes downhole devices for performing a variety of
functions. Exemplary downhole devices include devices that control the
drilling flow rate and flow paths. For example, the system can include one or
more flow-control devices that can stop the flow of the fluid in the drill
striny
and/or the annulus. Such flow-control devices can be configured to direct
fluid in drill string into the annulus and/or bypass return fluid around the
APO
device. Another exemplary downhole device can be configured for
processing the cuttings (e.g., reduction of cutting size) and other debris
flowing in the annulus. For example, a comminution device can be disposed
in the annulus upstream of the APD device.
In a preferred embodiment, sensors communicate with a controller via
a telemetry system to maintain the wellbore pressure at a zone of interest at
a
selected pressure or range of pressures. The sensors are strategicall y
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positioned throughout the system to provide information or data relating to
one or more selected parameters of interest such as drilling parameters,
drilling assembly or BHA parameters, and formation or formation evaluation
parameters. The controller for suitable for drilling operations preferably
includes programs for maintaining the wellbore pressure at zone at under-
balance condition, at at-balance condition or at over-balanced condition. The
controller may be programmed to activate downhole devices according to
programmed instructions or upon the occurrence of a particula r condition.
Exemplary configurations for the APD Device and associated drive
includes a moineau-type pump coupled to positive displacernent motor/drive
via a shaft assembly. Another exemplary configuration includes a turbine
drive coupled to a centrifugal-type pump via a shaft assembly. Preferably, a
high-pressure seal separates a supply fluid flowing through the motor from a
return fluid flowing through the pump. In a preferred embodiment, the seal is
configured to bear either or both of radial and axial (thrust) forces.
In still other configurations, a positive displacement motor can drive an
intermediate device such as a hydraulic motor, which drives the APD Device.
Alternatively, a jet pump can be used, which can eliminate the need for a
drive/motor. Moreover, pumps incorporating one or more pistons, such as
hammer pumps, may also be suitable for certain applications. In still other
configurations, the APD Device canb be driven by an electric motor. The
electric motor can be p ositioned e xternal to a drill string o r fi ormed i
ntegral
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with a drill string. In a preferred arrangement, varying the speed of the
electrical motor directly controls the speed of the rotor in the APD device,
and
thus the pressure differential across the APD Device.
Bypass devices a re p rovided to a Ilow f luid circulation i n the wellbore
during tripping of the system, to control the operating set points of the APD
Device and/or associated drive/motor, and to provide a discharge mechanism
to relieve fluid pressure. For examples, the bypass devices can selectively
channel fluid around the motor/drive and the APD Device and selectively
discharge drilling fluid from the drill string into the annulus. In one
arrangement, the bypass device for the pump can also function as a particle
bypass line for the APD device. Alternatively, a separate particle bypass can
be used in addition to the pump bypass for such a function. Additionally, an
annular seal (not shown) in certain embodiments can be disposed around the
APD device to enable a pressure differential across the APD Device.
In certain embodiments of the present invention, one or more of the
above-described components utilize a modular construction (i.e., formed as
modules having a standardized construction). Modular construction facilitates
repair and/or maintenance of a wellbore drilling assembly by enabling the
component needing w ork t o b e readily r emoved f rom t he d rilling a
ssembly.
Additionally, the modular construction can enhance the overall operating
capabilities of the drilling assembly. Generally speaking, components of a
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drilling assembly have operating set points, operating parameters and
characteristics that, if changed, can increase or decrease overall drilling
efficiency. An exemplary, but not exclusive, list of such set points,
operating
parameters and characteristics includes: rotational speed, pressure
differentials in the supply fluid or return fluid, torque output, and fluid
flow rate.
Moreover, the drilling environment can also impact drilling efficiency.
Exemplary environmental factors or conditions that influence drilling
efficiency
include loadings (stress, strain), temperature, wellbore fluid chemistry,
cutting
composition, and volume of cuttings in the return fluid. Modular components
that are configured to have a specified operating parameter or operate in a
particular environmental condition can be changed out as environmental
conditions change and/or as different operating parameters are needed to
provide optimal operation.
By way of illustration, components of a wellbore drilling assembly that
are amenable to modular construction include the APD Device, the motor
driving the modular APD Device, the comminution device, and the annular
seal. Suitable modular pumps can be configured to operate at different
rotational speeds, flow rates, and pressure differentials. Other embodiments
of modular pumps can generate the given pressure differential using multiple
stages. M odular motors can be d esigned to h ave d ifferent o perating RPM
and/or torque. Modular comminution devices can be configured for optimal
performance under a different operating parameter such a selected flow rate,
cutting composition, rotational speed of the driving mechanism, and volume of
cuttings in the return fluid. Modular annular seals can be constructed for
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specified wellbore diameters or ranges of wellbore diameters as well as
environmental conditions such as wellbore pressures and wellbore fluid
chemistry.
Modular construction can also be extended to other aspects of the
drilling assembly, such as internal seals. For instance, the high-pressure
seals used in conjunction with the APD Device and/or motor can be a
hydrodynamic seal that provides a selected leak or flow rates. In one
embodiment, the seal includes a concentrically arranged inner sleeve and
outer sleeve. A gap between the inner sleeve and the outer sleeve permits a
predetermined or specified amount of drilling fluid to leak through between
the concentric sleeves. Different seal modules can provide different degrees
of leak rates. The different seal modules can also be configured have
different functional characteristics such as radial support.
Thus, it should be appreciated that for a given drilling environment,
the appropriate configuration or re-configuration of one or more modules in
the wellbore drilling system can enhance drilling efficiency and increase
system life by reducing sub-optimal operation.
Accordingly, in one aspect of the present invention there is provided a
drilling system for drilling a wellbore, comprising:
(a) a drill string having a drill bit at an end thereof;
(b) a source supplying drilling fluid under pressure into the drill string
(a "supply fluid"), the drilling fluid returning uphole via an annulus around
the
drill string (a "return fluid");
(c) a modular tool in communication with the return fluid for reducing
pressure in the wellbore downhole of the modular tool, said modular tool
having at least one interchangeable modular unit;
(d) an active pressure differential device ("APD Device") associated
with the modular tool to create a pressure drop across said APD Device to
reduce pressure in the wellbore downhole of the APD device; and
(e) a drive assembly coupled to said APD Device for energizing said
APD Device.
According to another aspect of the present invention there is provided
a drilling system for drilling a wellbore, comprising:
(a) a drill string having a drill bit at an end thereof;
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(b) a source of drilling fluid supplying drilling fluid under pressure into
the drill string (a "supply fluid"), the drilling fluid returning uphole via
an
annulus around the drill string (a "return fluid");
(c) an active pressure differential device ("APD Device") associated
with the return fluid to create a pressure drop across said APD Device to
reduce pressure in the wellbore downhole of the APD Device;
(d) a drive assembly coupled to said APD Device for energizing said
APD Device; and
(e) a high-pressure seal associated with said drive assembly, said
seal configure to provide a controlled leakage of pressurized drilling fluid
out
of said drive assembly.
Examples of the more important features of the invention have been
summarized (albeit rather broadly) in order that the detailed description
thereof that follows may be better understood and in order that the
contributions they represent to the art may be appreciated. There are, of
course, additional features of the invention that will be described
hereinafter
and which will form the subject of the claims appended hereto.
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BRIEF DESCRIPTION OF THE DRAWINGS
For detailed understanding of the present invention, reference should
be made to the following detailed description of the preferred embodiment,
taken in conjunction with the accompanying drawing:
Figure 1A is a schematic illustration of one embodiment of a system
using an active pressure differential device to manage pressure in a
predetermined wellbore location;
Figure 1 B graphically illustrates the effect of an operating active
pressure differential device upon the pressure at a predetermined wellbore
location;
Figure 2 is a schematic elevation view of Figure IA after the drill string
and the active pressure differential device have moved a certain distance in
the earth formation from the location shown in Figure 1A;
Figure 3 is a schematic elevation view of an alternative embodiment of
the wellbore system wherein the active pressure differential device is
attached
to the wellbore inside;
Figures 4A-D are schematic illustrations of one embodiment of an
arrangement according to the present invention wherein a positive
displacement motor is coupled to a positive displacement pump (the APD
Device);
Figures 5A and 5B are schematic illustrations of one embodiment of
an arrangement according to the present invention wherein a turbine drive is
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coupled to a centrifugal pump (the APD Device);
Figure 6A is a schematic illustration of an embodiment of an
arrangement according to the present invention wherein an electric motor
disposed on the outside of a drill string is coupled to an APD Device;
Figure 6B is a schematic illustration of an embodiment of an
arrangement according to the present invention wherein an electric motor
disposed within a drill string is coupled to an APD Device;
Figure 7 is a schematic illustration of an embodiment of an
arrangement according to the present invention wherein the wellbore drilling
system includes at least one modular component; and
Figure 8 is a schematic illustration of an embodiment of a modular
seal arrangement according to the present invention.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Referring initially to Figure 1A, there is schematically illustrated a
system for performing one or more operations related to the construction,
logging, completion or work-over of a hydrocarbon producing well. In
particular, Figure 1A shows a schematic elevation view of one embodiment of
a wellbore drilling system 100 for drilling wellbore 90 using conventional
drilling fluid circulation. The drilling system 100 is a rig for land wells
and
includes a drilling platform 101, which may be a drill ship or another
suitable
surface workstation such as a floating platform or a semi-submersible for
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offshore wells. For offshore operations, additional known equipment such as
a riser and subsea wellhead will typically be used. To drill a wellbore 90,
well
control equipment 125 (also referred to as the wellhead equipment) is placed
above the wellbore 90. The wellhead equipment 125 includes a blow-out-
preventer stack 126 and a lubricator (not shown) with its associated flow
control.
This system 100 further includes a well tool such as a drilling assembly
or a bottomhole assembly ("BHA") 135 at the bottom of a suitable umbilical
such as drill string or tubing 121 (such terms will be used interchangeably).
In
a preferred embodiment, the BHA 135 includes a drill bit 130 adapted to
disintegrate rock and earth. ~ The bit can be rotated by a surface rotary
drive
or a motor using pressurized fluid (e.g., mud motor) or an electrically driven
motor. The tubing 121 can be formed partially or fully of drill pipe, metal or
composite coiled tubing, liner, casing or other known members. Additionally,
the tubing 121 can i nclude d ata a nd p ower transmission carriers s uch
fluid
conduits, fiber optics, and metal conductors. Conventionally, the tubing 121
is placed at the drilling platform 101. To drill the wellbore 90, the BHA 135
is
conveyed from the drilling platform 101 to the wellhead equipment 125 and
then inserted into the wellbore 90. The tubing 121 is moved into and out of
the wellbore 90 by a suitable tubing injection system.
During drilling, a drilling fluid from a surface mud system 22 is pumped
under pressure down the tubing 121 (a "supply fluid"). The mud system 22
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includes a mud pit or supply source 26 and one or more pumps 28. In one
embodiment, the supply fluid operates a mud motor in the BHA 135, which in
turn rotates the drill bit 130. The drill string 121 rotation can also be used
to
rotate the drill bit 130, either in conjunction with or separately from the
mud
motor. The drill bit 130 disintegrates the formation (rock) into cuttings 147.
The drilling fluid leaving the drill bit travels uphole through the annulus
194
between the drill string 121 and the wellbore wall or inside 196, carrying the
drill cuttings 147 therewith (a "return fluid"). The return fluid discharges
into a
separator (not shown) that separates the cuttings 147 and other solids from
the return fluid and discharges the clean fluid back into the mud pit 26. As
shown in Figure IA, the clean mud is pumped through the tubing 121 while
the mud with cuttings 147 returns to the surface via the annulus 194 up to the
wellhead equipment 125.
Once the well 90 has been drilled to a certain depth, casing 129 with a
casing shoe 151 at the bottom is installed. The drilling is then continued to
drill the well to a desired depth that will include one or more production
sections, such as section 155. The section below the casing shoe 151 may
not be cased until it is desired to complete the well, which leaves the bottom
section of the well as an open hole, as shown by numeral 156.
As noted above, the present invention provides a drilling system for
controlling bottomhole pressure at a zone of interest designated by the
numeral 155 and thereby the ECD effect on the wellbore. In one embodiment
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of the present invention, to manage or control the pressure at the zone 155,
an active pressure differential device ("APD Device") 170 is fluidicly coupled
to return fluid downstream of the zone of interest 155. The active pressure
differential device is a device that is capable of creating a pressure
differential
"AP" across the device. This controlled pressure drop reduces the pressure
upstream of the APD Device 170 and particularly in zone 155.
The system 100 also includes downhole devices that separately or
cooperatively perform one or more functions such as controlling the flow rate
of the drilling fluid and controlling the flow paths of the drilling fluid.
For
example, the system 100 can include one or more flow-control devices that
can stop the flow of the fluid in the drill string and/or the annulus 194.
Figure
1A shows an exemplary flow-control device 173 that includes a device 174
that can block the fluid flow within the drill string 121 and a device 175
that
blocks can block fluid flow through the annulus 194. The device 173 can be
activated when a particular condition occurs to insulate the well above and
below the flow-control device 173. For example, the flow-control device 173
may be activated to block fluid flow communication when drilling fluid
circulation is stopped so as to isolate the sections above and below the
device 173, thereby. maintaining the wellbore below the device 173 at or
substantially at the pressure condition prior to the stopping of the fluid
circulation.
The flow-control devices 174, 175 can also be configured to selectively
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control the flow path of the drilling fluid. For example, the flow-control
device
174 in the drill pipe 121 can be configured to direct some or all of the fluid
in
drill string 121 into the annulus 194. Moreover, one or both of the flow-
control
devices 174, 175 can be configured to bypass some or all of the return fluid
around the APD device 170. Such an arrangement may be useful, for
instance, to assist in lifting cuttings to the surface. The flow-control
device
173 may include check-valves, packers and any other suitable device. Such
devices may automatically activate upon the occurrence of a particular event
or condition.
The system 100 also includes downhole devices for processing the
cuttings (e.g., reduction of cutting size) and other debris flowing in the
annulus 194. For example, a comminution device 176 can be disposed in the
annulus 194 upstream of the APD device 170 to reduce the size of entrained
cutting and other debris. The comminution device 176 can use known
members such as blades, teeth, or rollers to crush, pulverize or otherwise
disintegrate cuttings and debris entrained in the fluid flowing in the annulus
194. The comminution device 176 can be operated by an electric motor, a
hydraulic motor, by rotation of drill string or other suitable means. The
comminution device 176 can also be integrated into the APD device 170. For
instance, if a multi-stage turbine is used as the APD device 170, then the
stages adjacent the inlet to the turbine can be replaced with blades adapted
to cut or shear particles before they pass through the blades of the remaining
turbine stages.
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Sensors Sl_õ are strategically positioned throughout the system 100 to
provide information or data relating to one or more selected parameters of
interest (pressure, flow rate, temperature). In a preferred embodiment, the
downhole devices and sensors Sl.,, communicate with a controller 180 via a
telemetry system (not shown). Using data provided by the sensors Sl.,,, the
controller 180 maintains the wellbore pressure at zone 155 at a selected
pressure or range of pressures. The controller 180 maintains the selected
pressure by controlling the APD device 170 (e.g., adjusting amount of energy
added to the return fluid line) and/or the downhole devices (e.g., adjusting
flow rate through a restriction such as a valve).
When configured for drilling operations, the sensors Sq.,, provide
measurements relating to a variety of drilling parameters, such as fluid
pressure, fluid flow rate, rotational speed of pumps and like devices,
temperature, weight-on bit, rate of penetration, etc., drilling assembly or
BHA
parameters, such as vibration, stick slip, RPM, inclination, direction, BHA
location, etc. and formation or formation evaluation parameters commonly
referred to as measurement-while-drilling parameters such as resistivity,
acoustic, nuclear, NMR, etc. One preferred type of sensor is a pressure
sensor for measuring pressure at one or more locations. Referring still to
Fig.
1A, pressure sensor P, provides pressure data in the BHA, sensor P2
provides pressure data in the annulus, pressure sensor P3 in the supply fluid,
and pressure sensor P4 provides pressure data at the surface. Other
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pressure sensors may be used to provide pressure data at any other desired
place in the system 100. Additionally, the system 100 includes fluid flow
sensors such as sensor V that provides measurement of fluid flow at one or
more places in the system.
Further, the status and condition of equipment as well as parameters
relating to ambient conditions (e.g., pressure and other parameters listed
above) in the system 100 can be monitored by sensors positioned throughout
the system 100: exemplary locations including at the surface (S1), at the APD
device 170 (S2), at the wellhead equipment 125 (S3), in the supply fluid (S4),
along the tubing 121 (S5), at the well tool 135 (S6), in the return fluid
upstream of the APD device 170 (S7), and in the return fluid downstream of
the APD device 170 (S8). It should be understood that other locations may
also be used for the sensors Si.,,.
The controller 180 for suitable for drilling operations preferably includes
programs for maintaining the wellbore pressure at zone 155 at under-balance
condition, at at-balance condition or at over-balanced condition. The
controller 180 includes one or more processors that process signals from the
various sensors in the drilling assembly and also controls their operation.
The
data provided by these sensors S1.,, and control s ignals transmitted by the
controller 180 to control downhole devices such as devices 173-176 are
communicated by a suitable two-way telemetry system (not shown). A
separate processor may be used for each sensor or device. Each sensor
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may also have additional circuitry for its unique operations. The controller
180, which may be either downhole or at the surface, is used herein in the
generic sense for sirnplicity and ease of understanding and not as a
limitation
because the use and operation of such controllers is known in the art. The
controller 180 preferably contains one or more microprocessors or micro-
controllers for processing signals and data and for performing control
functions, solid state memory units for storing programmed instructions,
models (which may be interactive models) and data, and other necessary
control circuits. The microprocessors control the operations of the various
sensors, provide communication among the d ownhole sensors and p rovide
two-way data and signal communication between the drilling assembly 30,
downhole devices such as devices 173-175 and the surface equipment via
the two-way telemetry. I n o ther embodiments, t he controller 180 c an b e a
hydro-mechanical device that incorporates known mechanisms (valves,
biased m embers, lin kages cooperating to a ctuate tools u nder, for example,
preset conditions).
For convenience, a single controller 180 is shown. It should be
understood, however, that a plurality of controllers 180 can also be used. For
example, a downhole controller can be used to collect, process and transmit
data to a surface controller, which further processes the data and transmits
appropriate control signals downhole. Other variations for dividing data
processing tasks and generating control signals can also be used.
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In general, however, during operation, the controller 180 receives the
information regarding a parameter of interest and adjusts one or more
downhole devices and/or APD device 170 to provide the desired pressure or
range or pressure in the vicinity of the zone of interest 155. For example,
the
controller 180 can receive pressure information from one or more of the
sensors (SI-Sõ) in the system 100. The controller 180 may control the APD
Device 170 in response to one or more of: pressure, fluid flow, a formation
characteristic, a wellbore characteristic and a fluid characteristic, a
surface
measured parameter or a parameter measured in the drill string. The
controller 180 determines the ECD and adjusts the energy input to the APD
device 170 to maintain the ECD at a desired or predetermined value or within
a desired or predetermined range. The wellbore system 100 thus provides a
closed loop system for controlling the ECD in response to one or more
parameters of interest during drilling of a wellbore. This system is
relatively
simple and efficient and can be incorporated into new or existing drilling
systems and readily adapted to support other well construction, completion,
and work-over activities.
In the embodiment shown in Figure IA, the APD Device 170 is shown
as a turbine attached to the drill string 121 that operates within the annulus
194. Other embodiments, described in further detail below can include
centrifugal pumps, positive displacement pump, jet pumps and other like
devices. During drilling, the APD Device 170 moves in the wellbore 90 along
with the drill string 121. The return fluid can flow through the APD Device
170
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whether or not the turbine is operating. However, the APD Device 170, when
operated creates a differential pressure thereacross.
As described above, the system 100 in one embodiment includes a
controller 180 that includes a memory and peripherals 184 for controlling the
operation of the APD Device 170, the devices 173-176, and/or the bottomhole
assembly 135. In Figure 1A, the controller 180 is shown placed at the
surface. It, however, may be located adjacent the APD Device 170, in the
BHA 135 or at any other suitable I ocation. The controller 180 controls the
APD Device to create a desired amount of AP across the device, which alters
the bottomhole pressure accordingly. Alternatively, the controller 180 may be
programmed to activate the flow-control device 173 (or other downhole
devices) according to programmed instructions or upon the occurrence of a
particular condition. Thus, the controller 180 can control the APD Device in
response to sensor data regarding a parameter of interest, according to
programmed instructions provided to said APD Device, or in response to
instructions provided to said APD Device from a remote location. The
controller 180 can, thus, operate autonomously or interactively.
During drilling, the controller 180 controls the operation of the APD
Device to create a certain pressure differential across the device so as to
alter
the pressure on the formation or the bottomhole pressure. The controller 180
may be programmed to maintain the wellbore pressure at a value or range of
values that provide an under-balance condition, an at-balance condition or an
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over-balanced condition. In one embodiment, the differential pressure may
be altered by altering the speed of the APD Device. For instance, the
bottomhole pressure may be maintained at a p reselected value or w ithin a
selected range relative to a parameter of interest such as the formation
pressure. The controller 180 may receive signals from one or more sensors
in the system 100 and in response thereto control the operation of the APD
Device to create the desired pressure differential. The controller 180 may
contain pre-programmed instructions and autonornously control the APD
Device or respond to signals received from another device that may be
remotely located from the APD Device.
Figure 1 B graphically illustrates the ECD control provided by the
above-described embodiment of the present invention and references Figure
IA for convenience. Figure 1A shows the APD device 170 at a depth D1 and
a representative location in the wellbore in the vicinity of the well tool 30
at a
lower depth D2. Figure 1 B provides a depth versus pressure graph having a
first curve C 1 representative of a p ressure g radient b efore operation of
the
system 100 and a second c urve C 2 representative o f a p ressure gradients
during operation of the system 100. Curve C3 represents a theoretical curve
wherein the ECD condition is not present; i.e., when the well is static and
not
circulating and is free of drill cuttings. It will be seen that a target or
selected
pressure at depth D2 under curve C3 cannot be met with curve Cl.
Advantageously, the system 100 reduces the hydrostatic p ressure at depth
Dl and thus shifts the pressure gradient as shown by curve C3, which can
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provide the desired predetermined pressure at depth D2. In most instances,
this shift is roughly the pressure drop provided by the APD device 170.
Figure 2 shows the drill string after it has rmoved the distance "d"
shown by tl - t2. Since the APD Device 170 is attached to the drill string
121,
the APD Device 170 also is shown moved by the dista nce d.
As noted earlier and shown in Figure 2, an APD Device 170a may be
attached to the wellbore in a manner that will allow the drill string 121 to
move
while the APD Device 170a remains at a fixed location. Figure 3 shows an
embodiment wherein the APD Device is attached to the wellbore inside and is
operated by a suitable device 172a. Thus, the APD device can be attached
to a location stationary relative to said drill string such as a casing, a
liner, the
wellbore annulus, a riser, or other suitable wellbore equipment. The APD
Device 170a is preferably installed so that it is in a cased upper section
129.
The device 170a is controlled in the manner described with respect to the
device 170 (Fig 1A).
Referring now to Figures 4A-D, there is sche matically illustrated one
arrangement wherein a positive displacement motor/drive 200 is coupled to a
moineau-type pump 220 via a shaft assembly 24-0. The motor 200 is
connected to an upper string section 260 through which drilling fluid is
pumped from a surface location. The pump 220 is connected to a lower drill
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string section 262 on which the bottomhole assembly (not shown) is attaclhed
at an end thereof. The motor 200 includes a rotor 202 and a stator 204.
Similarly, the pump 220 includes a rotor 222 and a stator 224. The desigrn of
moineau-type pumps and motors are known to one skilled in the art and _ will
not be discussed in further detail.
The shaft assembly 240 transmits the power generated by the motor
200 to the pump 220. One preferred shaft assembly 240 includes a motor
flex shaft 242 connected to the motor rotor 202, a pump flex shaft 244
connected to the pump rotor 224, and a coupling shaft 246 for joining the -
first
and second shafts 242 and 244. In one arrangement, a high-pressure seal
248 is disposed about the coupling shaft 2 46. As i s k nown, the rotors f or
moineau-type motors/pump are subject to eccentric motion during rotation.
Accordingly, the coupling shaft 246 is preferably articulated or forr-ned
sufficiently flexible to absorb this eccentric motion. Alternately or in
combination, the shafts 242, 244 can be configured to flex to accommodate
eccentric motion. Radial and axial forces can be borne by bearings 250
positioned along the shaft assembly 240. In a preferred embodiment, the
seal 248 is configured to bear either or both of radial and axial (thrust)
forces.
In certain arrangements, a speed or torque converter 252 can be used to
convert speed/torque of the motor 200 to a second speed/torque for the pump
220. By speed/torque converter it is meant known devices such as variable
or fixed ratio mechanical gearboxes, hydrostatic torque converters, ancl a
hydrodynamic converters. It should be understood that any number of
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arrangements and devices can be used to transfer power, speed, or torque
from the motor 200 to the pump 220. For example, the shaft assernbly 240
can utilize a single shaft instead of multiple shafts.
As described earlier, a comminution device can be used to process
entrained cutting in the return fluid before it enters the pump 200. Such a
comminution device (Figure IA) can be coupled to t he d rive 2 00 r p ump
220 and operated thereby. F or i nstance, o ne such comminution d evice or
cutting mill 270 can include a shaft 272 coupled to the pump rotor 224. The
shaft 272 can include a conical head or hammer element 274 rmounted
thereon. During rotation, the eccentric motion of the pump rotor 224 will
cause
a corresponding radial motion of the shaft head 274. This radial mootion can
be used to resize the cuttings between the rotor and a comminution device
housing 276.
The Figures 4A-D arrangement also includes a supply flow path 290
to carry supply fluid from the device 200 to the lower drill string section
262
and a return flow path 292 to channel return fluid from the casing irnterior
or
annulus into and out of the pump 220. The high pressure seal 248 is
interposed between the flow paths 290 and 292 to prevent fluid leaks,
particularly from the high pressure fluid in the supply flow path 290 into the
return flow path 292. The seal 248 can be a high-pressure seal, a
hydrodynamic seal or other suitable seal and formed of rubber, an elastomer,
metal or composite.
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Additionally, bypass devices are provided to allow fluid circulation
during tripping of the downhole devices of the system 100 (Fig. IA), to
control
the operating set points of the motor 200 and pump 220, and to provide
safety pressure relief along either or both of the supply flow path 290 and
the
return flow path 292. Exemplary bypass devices include a circulation bypass
300, motor bypass 310, and a pump bypass 320.
The circulation bypass 300 selectively diverts supply fluid into the
annulus 194 (Fig. IA) or casing C interior. The circulation bypass 300 is
interposed generally between the upper drill string section 260 and the motor
200. One preferred circulation bypass 300 includes a biased valve member
302 that opens when the flow-rate drops below a predetermined valve. When
the valve 302 is open, the supply fluid flows along a channel 304 and exits at
ports 306. More generally, the circulation bypass can be configured to
actuate upon receiving an actuating signal and/or detecting a predetermined
value or range of values relating to a parameter of interest (e.g., flow rate
or
pressure of supply fluid or operating parameter of the bottomhole assembly).
The circulation bypass 300 can be used to facilitate drilling operations and
to
selective increase the pressure/flow rate of the return fluid.
The motor bypass 310 selectively channels conveys fluid around the
motor 200. The motor bypass 310 includes a valve 312 and a passage 314
formed through the motor rotor 202. A joint 316 connecting the motor rotor
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202 to the first shaft 242 includes suitable passages (not shown) that allow
the supply fluid to exit the rotor passage 314 and enter the supply flow path
290. Likewise, a pump bypass 320 selectively conveys fluid around the
pump 220. The pump bypass includes a valve and a passage formed
through the pump rotor 222 or housing. The pump bypass 320 can also be
configured to function as a particle bypass line for the APD device. For
example, the pump bypass can be adapted with known elements such as
screens o r f ilters to s electively c onvey cuttings or p articles entrained
i n the
return fluid that are greater than a predetermined size around the APD
device. Alternatively, a separate particle bypass can be used in addition to
the pump bypass for such a function. Alternately, a valve (not shown) in a
pump housing 225 can divert fluid to a conduit parallel to the pump 220.
Such a v alve c an b e c onfigured t o open w hen the flow rate drops below a
predetermined value. Further, the bypass device can be a design internal
leakage in the pump. That is, the operating point of the pump 220 can be
controlled by providing a preset or variable amount of fluid leakage in the
pump 220. Additionally, pressure valves can be positioned in the pump 220
to discharge fluid in the event an overpressure condition or other
predetermined condition is detected.
Additionally, an annular seal 299 in certain embodiments can be
disposed around the APD device to direct the return fluid to flow into the
pump 220 (or more generally, the APD device) and to allow a pressure
differential across the pump 220. The seal 299 can be a solid or pliant ring
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member, an expandable packer type element that expands/contracts upon
receiving a command signal, or other member that substantially prevents the
return fluid from flowing between the pump 220 (or more generally, the APD
device) and the casing or wellbore wall. In certain applications, the
clearance
between the APD device and adjacent wall (either casing or wellbore) may be
sufficiently small as to not require an annular seal.
During operation, the motor 200 and pump 220 are positioned in a well
bore location such as i n a casing C. Drilling fluid (the supply fluid)
flowing
through the upper drill string section 260 enters the motor 200 and causes the
rotor 202 to rotate. This rotation is transferred to the pump rotor 222 by the
shaft assembly 240. As is known, the respective lobe profiles, size and
configuration of the motor 200 and the pump 220 can be varied to provide a
selected speed or torque curve at given flow-rates. Upon exiting the motor
200, the supply fluid flows through the supply flow path 290 to the lower
drill
string section 262, and ultimately the bottomhole assembly (not shown). The
return fluid flows up through the wellbore annulus (not shown) and casing C
and enters the cutting mill 270 via a inlet 293 for the return flow path 292.
The
flow g oes t hrough the c utting m ill 270 and e nters t he pump 2 20. I n
this
embodiment, the controller 180 (Fig. 1A) can be programmed to control the
speed o f the m otor 200 a nd t hus t he operation of the pump 220 (the APD
Device in this instance).
It should be understood that the above-described arrangement is
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merely one exemplary use of positive displacement motors and pumps. For
example, while the positive displacement motor and pump are shown in
structurally in series in Figures 4A-D, a suitable arrangement can also have a
positive displacement m otor and pump i n parallel. For example, the motor
can be concentrically disposed in a pump.
Referring now to Figures 5A-B, there is schematically illustrated one
arrangement wherein a turbine drive 350 is coupled to a centrifugal-type
pump 370 via a shaft assembly 390. The turbine 350 includes stationary and
rotating blades 354 and radial bearings 402. The centrifugal-type pump 370
includes a housing 372 and multiple impeller stages 374. The design of
turbines and centrifugal pumps are known to one skilled in the art and will
not
be discussed in further detail.
The shaft assembly 390 transmits the power generated by the turbine
350 to the centrifugal pump 370. One preferred shaft assembly 350 includes
a turbine shaft 392 connected to the turbine blade assembly 354, a pump
shaft 394 connected to the pump impeller stages 374, and a coupling 396 for
joining the turbine and pump shafts 392 and 394.
The Figure 5A-B arrangement also includes a supply flow path 410 for
channeling supply fluid shown b y a rrows d esignated 416 and a return flow
path 418 to channel return fluid shown by arrows designated 424. The supply
flow path 410 includes an inlet 412 directing supply fluid into the turbine
350
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and an axial passage 413 that conveys the supply fluid exiting the turbine 350
to an outlet 414. The return flow path 418 includes an inlet 420 that directs
return fluid into the centrifugal pump 370 and an outlet 422 that channels the
return fluid into the casing C interior or wellbore annulus. A high pressure
seal 400 is interposed between the flow paths 410 and 418 to reduce fluid
leaks, particularly from the high pressure fluid in the supply flow path 410
into
the return flow path 418. A small leakage rate is desired to cool and
lubricate
the axial and radial bearings. Additionally, a bypass 426 can be provided to
divert supply fluid from the turbine 350. Moreover, radial and axial forces
can
be borne by bearing assemblies 402 positioned along the shaft assembly
390. Preferably a comminution device 373 is provided to reduce particle size
entering the centrifugal pump 3 70. I n a preferred embodiment, one of the
impeller stages is modified with shearing blades or elements that shear
entrained particles to reduce their size. In certain arrangements, a speed or
torque converter 406 can be used to convert a first speed/torque of the motor
350 to a second speed/torque for the centrifugal pump 370. It should be
understood that any number of arrangements and devices can be used to
transfer power, speed, or torque from the turbine 350 to the pump 370. For
example, the shaft assembly 390 can utilize a single shaft instead of multiple
shafts.
It should be appreciated that a positive displacement pump need not
be matched with only a positive displacement motor, o r a centrifugal pump
with only a turbine. In certain applications, operational speed or space
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considerations may lend itself to an arrangement wherein a positive
displacement drive can effectively energize a centrifugal pump ora turbine
drive energize a positive displacement pump. It should also be appreciated
that the present invention is not limited to the above-described arrangements.
For example, a positive displacement motor can drive an intermediate device
such as an electric motor or hydraulic motor provided with an encapsulated
clean hydraulic reservoir. I n such an arrangement, the hydraulic motor (or
produced electric power) drives the pump. These arrangements can eliminate
the leak paths between the high-pressure supply fluid and the return fluid and
therefore eliminates the need for high-pressure seals. Alternatively, a jet
pump can be used. In an exemplary arrangement, the supply fluid is divided
into two streams. The first stream is directed to the BHA. The second
stream is accelerated by a nozzle and discharged with high velocity into the
annulus, thereby effecting a reduction in annular pressure. Pumps
incorporating one or more pistons, such as hammer pumps, may also be
suitable for certain applications.
Referring now to Figure 6A, there is schematically illustrated one
arrangement wherein an electrically driven pump assembly 500 includes a
motor 510 that is at least partially positioned external to a drill string
502. In a
conventional manner, the motor 510 is coupled to a pump 520 via a shaft
assembly 530. A supply flow path 504 conveys supply fluid designated with
arrow 505 and a return flow path 506 conveys return fluid designated with
arrow 507. As can b e seen, the F igure 6A arrangement d oes n ot i nclude
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leak paths through which the high-pressure supply fluid 505 can invade the
return flow path 506. Thus, there is no need for high pressures seals.
In one embodiment, the motor 510 includes a rotor 512, a stator 514,
and a rotating seal 516 that protects the coils 512 and stator 514 from
drilling
fluid and cuttings. In one embodiment, the stator 514 is fixed on the outside
of
the drill string 502. The coils of the rotor 512 and stator 514 are
encapsulated
in a material or housing that prevents damage from contact with wellbore
fluids. Preferably, the motor 5 10 interiors are filled with a clean hydraulic
fluid. In another embodiment not shown, the rotor is positioned within the
flow
of the return fluid, thereby eliminating the rotating seal. In such an
arrangement, the stator can be protected with a tube filled with clean
hydraulic fluid for pressure compensation.
Referring now to Figure 6B, there is schematically illustrated one
arrangement wherein an e lectrically d riven pump 550 includes a motor 570
that is at least partially formed integral with a drill string 552. In a
conventional manner, the motor 570 is coupled to a pump 590 via a s haft
assembly 580. A supply flow path 554 conveys supply fluid designated with
arrow 556 and a return flow path 558 conveys return f luid designated with
arrow 560. A s can be seen, t he F igure 6B arrangement d oes n ot i nclude
leak paths through which the high-pressure supply fluid 556 can invade the
return flow path 558. Thus, there is no need for high pressures seals.
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It should be appreciated that an electrical drive provides a relatively
simple method for controlling the APD Device. For instance, varying the
speed of the electrical motor will directly control the speed of the rotor in
the
APD device, and thus the pressure differential across the APD Device.
Further, in either of the Figure 6A or 6B arrangements, the pump 520 and
590 can be any suitable pump, and is preferably a multi-stage centrifugal-type
pump. Moreover, positive displacement type pumps such a screw or gear
type or moineau-type pumps may also be adequate for many applications.
For example, the pump configuration may be single stage or multi-stage and
utilize radial flow, axial flow, or mixed flow. Additionally, as described
earlier,
a comminution device positioned downhole of the pumps 520 and 590 can be
used to reduce the size of particles entrained in the return fluid.
It will be appreciated that many variations to the above-described
embodiments are possible. For example, a clutch element can be added to
the shaft assembly connecting the drive to the pump to selectively couple and
uncouple the drive and pump. Further, in certain applications, it may be
advantages to utilize a non-mechanical connection between the drive and the
pump. For instance, a magnetic clutch can be used to engage the drive and
the pump. In such an arrangement, the supply fluid and drive and the return
fluid and pump can remain separated. The speed/torque can be transferred
by a magnetic connection that couples the drive and pump elements, which
are separated by a tubular element (e.g., drill string). Additionally, while
certain elements have been discussed with respect to one or more particular
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embodiments, it should be understood that the present invention is not limited
to a ny such particular combinations. For example, e lements such as shaft
assemblies, bypasses, comminution devices and annular seals discussed in
the context of positive displacement drives can be readily used with electric
drive arrangements. Other embodiments within the scope of the present
invention that are not shown include a centrifugal pump that is attached to
the
drill string. The pump can include a multi-stage impeller and can be driven by
a hydraulic power unit, such as a motor. This motor may be operated by the
drilling fluid or by any other suitable manner. Still another embodiment not
shown includes an APD Device that is fixed to the drill string, which is
operated by the drill string rotation. In this embodiment, a number of
impellers are attached to the drill string. The rotation of the drill string
rotates
the impeller that creates a differential pressure across the device.
In certain embodiments of the present invention, o ne o r m ore of the
components described in reference to Figs. 1A-6B utilize a modular
construction. In one aspect, the term modular construction implies a
standardized structural configuration having generic or universal coupling
interfaces that enables a component to be interchangeable within the
wellbore drilling assembly. Thus, for instance, if a component fails or is in
need of maintenance, a replacement component is inserted in its place within
the drilling assembly. In another aspect, this term implies a component
available as a plurality of modules. Each module has a standardized housing
for interchangeability while also being functionally or operationally distinct
from one another (e.g., each module has different operating set point or
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operating range and/or different performance characteristics). Thus, as
drilling dynamics change, the component module having the appropriate
operating or performance characteristics for obtain optimal drilling
efficiency is
inserted intb the wellbore drilling assembly. Still other aspects and
advantages of the modular construction will become apparent in the following
description.
As is known, a number of factors can affect the overall cost of drilling a
wellbore and the quality of the wellbore drilled_ Exemplary factors include
the
lithology of the formation to be drilled, the complexity of the wellbore
trajectory, the geographical location (e.g., land-based or offshore), the
wellbore environment (e.g., pressure, temperature, etc.), and the operating
characteristics and limits of the drilling system.
Conventionally, a wellbore drilling assembly having a substantially fixed
or static configuration is used throughout the drilling a ctivity. H owever,
the
lithology o f a f ormation c an v ary f rom a relatively s oft e arth that i s
easy to
displace to earth containing hard rock that requires more energy to
disintegrate. As is known, adjustments to the drilling parameters to account
for changes in lithology can alter the stresses and loadings on the wellbore
drilling system as well as impact its efficiency. Also, it is now common for
the
planned trajectory of a wellbore to deviate from a vertical or plumb line. For
instance, the wellbore can include deviated sections, short-radius sections,
and horizontal sections in addition to vertical sections. Each such section
can
impose unique loadings on the wellbore drilling system. One method for
accommodating changes in drilling dynamics caused by these and other
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factors i s t o adjust certain drilling operating parameters (e.g., weight-on-
bit,
drilling fluid flow rate, drill bit rotation speed, etc.). Such adjustments,
however, may lead to sub-optimal drilling (e.g., reduced rate of penetration)
or
increased wear on the wellbore drilling assembly components. Another
method of dealing with changing drilling dynamics is to include sophisticated
control devices (e.g., flow restriction devices and bypass valves) within the
wellbore drilling assembly that control the operation of one or more of its
constituent components. The use of such control devices can increase the
complexity of the wellbore drilling assembly and increase its overall cost.
Referring now to Fig. 7, there is schematically shown a section of a
wellbore drilling assembly 600 having a modular APD Device 602 (e.g., a
pump), a modular motor 604 driving the modular APD Device 602, a modular
comminution device 606, and a modular annular seal 608. The modular
construction of these components provides flexibility in assembling a wellbore
drilling system 600 that operates optimally in each phase of drilling
operations
and facilitates the transportation, maintenance and repair of the wellbore
drilling system. As will be described below, any one of these above-
mentioned modular components can be formed as a plurality of
interchangeable units. Each interchangeable unit can have a specified a nd
different operating characteristic. Thus, the drilling assembly 600 can be
deployed in multiple configurations, each of which has a selected behavior
during operation and a selected response to a given drilling condition.
In one embodiment, the pump 602 is made available in a plurality of
interchangeable modular units. Each modular pump 602 is configured to
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operate a different set points or ranges of set points (e.g., rotational
speed,
flow rates, pressure differential, etc.). One or more of these rnodular units
can also be fitted with devices (e.g., bypass valves and pressure relief
valves)
that have different set points. Thus, in instances where a particular drilling
environment or operating condition causes the modular pump 602 to operate
sub-optimally, that modular pump 602 can be changed out with a modular
pump having operating characteristics more suited to the particular conditions
encountered. For example, the p ump m odule 6 02 may b e c hanged o ut to
increase or decrease the pressure differential produced in the return fluid
612. The modular construction can also provide flexibility in d esigning the
drilling assembly. For example, instead of using a single pump 602 to
generate a given pressure differential, a plurality of pump 602 rnodules can
be arranged in a serial fashion to generate the given pressure differential
across multiple stages. It should be appreciated that pressure differential is
merely one operating parameter than can be varied between successive
pump modules 602. The configurations of the pump 602 modules can also
be designed to account for different compositions of cuttings (e.g., rock size
or make-up) in the return fluid 612, the density of the return fluid 612,
drilling
fluid flow rates, etc.
The motor 604 can also be configured as interchangeable units having
specified set point or ranges of set points (e.g., operating RPM and/or
torque)
and can include control devices having different operating set points. T he
selection of the appropriate motor module 604 can be based, for example, on
the operating requirements of the pump 602, the characteristics of the
drilling
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fluid (e.g., flow rate or pressure), and the wellbore environment (e.g.,
loadings, temperature, etc.).
Also, in certain embodiments, the pump 602 and motor 604 can be
formed as an integral modular unit that can be readily inserted or removed
from a wellbore drilling assembly 600. Thus, each integral pump and motor
module can be adapted to provide distinct operating characteristics.
As discussed earlier, the cornminution device 606 processes entrained
cuttings before they enter the purnp 602. Like the modular motor 604 and
pump 602, the comminution device 606 can be made as a plurality of
modules. Each module can be co nfigured for optimal performance under a
different operating parameter such a selected flow rate, cutting composition,
rotational speed of the driving mechanism, volume of cuttings in the return
fluid 612, etc. Additionally, the modular comminution device 606 can be
configured to produce different sizes of reduced cuttings. Thus,
advantageously, the modular comminution device 606 can be changed-out to
match the operating requirements of the pump 602 (e.g., maximum particle
size in the return fluid 612 flowir-ig through the pump 602) and/or other
devices such as passage ways, valves, and other fluid conduits. It should be
noted that the comminution device modules 606 need not be structurally
identical. For instance, one module can be configured as a single stage
device having one chamber whe rein particles are crushed or otherwise
reduced in size. Still another module can include a multiple-stage device
having multiple chambers in which the particles are successively reduced in
size. Nor do the modules need to utilize the same action for reducing particle
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size. For instance, one module may use a crushing action whereas another
module may use a shearing action and still another module utilizes a
chemical agent to reduce particle size. Of course, in certain applications,
the
comminution device 606 can be omitted entirely.
As described earlier, the annular seal 608 selectively blocks, flow along
the annulus 616 formed between the wellbore drilling assembly 600 and
wellbore wall 618 to direct the return fluid 612 into the comminution device
606 (or pump 602 module). As is known, the wellbore drilling assembly 600
can be deployed in wellbores having various diameters. Accordingly, the
annular seal 608 can be formed as a plurality of modules, each of which is
suited for a specified wellbore diameter or range of wellbore diameters. The
annular seal modules 608 can also be formed to handle different wellbore
pressures, wellbore fluid chemistry, etc.
Additionally, features such as valves or safety devices associated with
the wellbore drilling system 600 can also be made modular to readily
accommodate expected changes in the loadings and operating parameters of
the wellbore drilling system 600. Referring now to Fig. 8, there is shown an
embodiment of a high-pressure seal 630 that, in one embodiment, is adapted
for modular construction. The seal 630 is used in conjunction with a motor
604 and pump 602 and is adapted to prevent the drilling fluid flowing between
the stator and rotor of the motor 604 from leaking excessively into a
relatively
lower pressure region. That is, the seal 630 has a pre-determined leak rate
that can be based on one or more operating conditions (discussed below).
In one embodiment, the seal 630 is a hydrodynamic seal that includes
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a concentrically arranged inner sleeve 632 and outer sleeve 634. The inner
sleeve 632 is fixed on a shaft assembly 636 and th e outer sleeve 634 is fixed
to a housing 638. A gap 640 between the inner sleeve 632 and the outer
sleeve 634 is sized to permit a predetermined or specified amount of drilling
fluid to leak through between the concentric sleeves 632 and 634. Because
the leak rate adversely affects the pressure differential available to drive
the
motor, one factor in determining the permissible leak rate is amount of
pressure and flow rate losses that can be tolerated from a motor efficiency
standpoint. Other factors include the amount of fluid needed to cool and
lubricate bearings such as axial bearings 642. Because acceptable leak rates
can vary depending on the particular drilling con ditions, one parameter or
operating set point that can be different for the various modules of the seal
630 is leak rates.
Still other parameters or operating conditions can be made different for
the various modules of the seal 630. For instance, in the embodiment shown
in Fig. 8, the seal 630 is also configured to operate as a radial bearing for
providing lateral stability for the motor 604 (Fig. 7). Thus, the modules of
the
seal 630 can have distinct and different degrees of lateral support. Moreover,
although two seals 630 are shown in the Fi g. 8 embodiment, other
embodiments can use one seal or three or more seal elements.
In one embodiment, the inner and outer sleeves 632, 634 include
surfaces adapted to withstand the abrasive o perating e nvironment. D uring
operation, the relative rotation between the inner and outer sleeves 602,604
can generate mechanical friction. Moreover, the E-iigh velocity of the
drilling
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fluid flowing through the gap 640 can cause wear. Accordingly, surfaces
expected to encounter wear from either or both of these sources are
hardened. For instance, the outer sleeve can be coated with a relatively hard
material (e.g., tungsten carbide) and the inner sleeve can i nclude hardened
inserts (e.g., tungsten carbide inserts). Still other treatments (e.g.,
carburizing, nitriding, etc.) can also be used in certain applications. The
sleeves 632,634 can be made modular in form with separate modules. Each
high-pressure seal module can be formed to have a different operational
characteristics such as leak rate and wear hardness. The rrodules can also
be configured to provide different degrees of radial support. It should be
understood, however, that the advantages of the described seal can also be
realized in embodiments that do not utilize a modular construction.
In one embodiment, the housings or enclosures of the above-
described components utilize a standardized interface. For example, the
housing of the components are provided standardized threads on one or
more of the opposing ends. Also, the shafts or other me= mbers extending
between the motor 604 and the pump 602 include complernentary male and
female connections (not shown). In other embodiments, devices such as flat
planes, splines and tongue-and-groove arrangements can also be used.
Moreover, a coupling or adapter can be used to join together modules in lieu
of (or in addition to) the modules being directly matable with one another.
The operating characteristics, set points and pararneters described
above are only some of the features that can be varied among the modules of
a given component. For instance, the modules can be mad e to have varying
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weights, I engths and diameters. The module enclosures and internals can
use different materials to have varying resistance to the wellbore environment
(wellbore fluids, chemical agents, etc.). Thus, it should be appreciated that
in
one aspect, what has been described is a wellbore drilling assembly formed
of at least one modular component. In one embodiment, the modular and
interchangeable component includes a plurality of units, each of which is
configured to have a specified operating set points, ope rating ranges,
component dimensions, component weight, and component response to
system operating parameters (e.g., flow rates, weight-on-bit, etc.). The
modules can have individualized responses to specified wellbore environment
or conditions (e.g., stresses, corrosive agents, vibration, etc.). In certain
embodiments, the joint arrangement for the modular component includes
complementary male and female couplings for connecting features such as
shafts and threads on one or both ends of the housing or enclosure.
A number of methodologies may be employed to advantageously apply
the above teachings. In one illustrative method, one or more components
making up a modular wellbore tool are selected for modula r construction.
One basis for this selection may be that a certain component may require
frequent change-outs (e.g., for maintenance or repair). Anothe r basis may be
that the operating capacity or range of a particular component can be
extended by use of a modular design. As a first step, the selected
components are constructed as modules (e.g., a drive module, a pump
module, a comminution device module, annular seal modules, and a high-
pressure seal module). A particular component may have a single modular
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configuration (Le., each module having the same operating characteristic) or
a plurality of modular configurations (i.e., each module having a different
operating capacity). In the next step, the individual component modules are
assembled as tool sub-modules. For example, a drive module and pump
module can be assembled into a first tool sub-module and a comminution
device module and annular seal module can be assembled into a second tool
module. Much like the individual component modules, the tool sub-modules
can each have a specified operating set point, range, characteristic and/or
response. Furthermore, the tool sub-modules can be formed to address
other factors such as ease of transportation, handling and storage. That is,
the tool sub-modules can be constructed to not exceed a particular weight or
length so that they may be more easily transported and deployed. Other
components such as high-pressure seal modules and modular valve modules
can be constructed to be inserted into these or other tool sub-assembly.
Finally, the tool sub modules are coupled using a suitable coupling to form a
modular tool. It should be a ppreciated that the operating characteristics of
the modular tool can be adjusted by interchanging individual modules (e.g.,
the pump module) or by interchanging tool sub-modules. Thus, in one
process of construction, a modular tool for controlling wellbore pressure is
assembled i n t hree s teps. F irst, individual components h aving specified o
r
discrete functions are formed as modular units. Second, these modular units
are formed into tool sub-modules. And third, the tool sub-modules are
assembled into the modular tool. It should be appreciated that the modular
construction not only enhances the overall operating capacity of the modular
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tool, but simplifies assembly, dis-assembly, repair, maintenance, handing,
shipment and storage.
While the foregoing disclosure is directed to the preferred
embodiments of the invention, various modifications will be apparent to tho se
skilled in the art. It is intended that all variations within the scope and
spirit of
the appended claims be embraced by the foregoing disclosure.
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