Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
Title: Active Controlled Bottomhole Pressure System and
Method With Continuous Circulation System
Inventors: Sven Krueger; Volker Krueger; Peter Aronstam;
Harald Grimmer; Roger Fincher; and Larry Watkins
Field of the Invention
[0001] 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
[0002] 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 drilling 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 and then
discharges at the bottom of the drill bit. The drilling fluid returns uphole
via
the annulus between the drill string and the wellbore 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.
[0003] For drilling wellbores under water (referred to in the industry as
"offshore" or "subsea" drilling) tubing is provided at a work station (located
on
1
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0004] 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 sea 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.
[0005] 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.
[0006] This term, ECD, describes the condition that exists when the drilling
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. This condition is exacerbated when drilling an offshore well. In
offshore wells, the difference between the fracture pressures in the shallow
2
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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.
[0007] 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 wellbore 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 wellbore
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 and 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 remainder of the fluid
circulation system). This so-called "dual density" approach is often referred
to
as drilling with compressible fluids.
[0008] Another method for changing the density gradient in a deepwater
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 wellbore 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
3
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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.
[0009] Another approach is described in U.S. Patent Application No.
09/353,275, filed on July 14, 1999 and assigned to the assignee of the
present application. The U.S. Patent Application No. 09/353,275 is
incorporated herein by reference in its entirety. 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.
[0010] 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 present system is relatively easy to incorporate in new and
existing systems.
4
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
SUMMARY OF THE INVENTION
[0011] The present invention provides wellbore systems for performing
downhole welibore 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. The umbilical can include wires for transmitting power
such as electrical downhole. 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 and
provides a conduit for moving the returning fluid to the surface.
[0012] In one embodiment of the present invention, an active pressure
differential device moves in the wellbore as the drill string is moved. In an
alternative embodiment, the active differential pressure device is attached to
the wellbore inside or wall and remains stationary relative to the wellbore
during drilling. The device is operated during 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.
[0013] 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.
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0014] In one embodiment, sensors communicate with a controller via a
communication link to maintain the wellbore pressure at a zone of interest at
a
selected pressure or range of pressures. The communication link can
include conductors, wires, cables in or adjacent the drill string that are
adapted to convey data signals and/or electrical power. The sensors are
strategically 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 particular
condition.
[0015] Exemplary configurations for the APD Device and associated drive
includes a moineau-type pump coupled to positive displacement motor/drive
via a shaft assembly. Another exemplary configuration incl,udes 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.
[0016] 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 can be driven by an electric motor. The
electric motor can be positioned external to a drill string or formed integral
with a drill string. In a preferred arrangement, varying the speed of the
6
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
electrical motor directly controls the speed of the rotor in the APD device,
and
thus the pressure differential across the APD Device.
[0017] Bypass devices are provided to allow fluid circulation in 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.
[0018] Embodiments of the present invention can be to manage wellbore
pressure even when the formation is not being actively drilled. For example,
embodiments of the present invention can be used to control pressure during
periods where joints are added to the drill string and when the drill string
is
tripped into or out of the wellbore. In one embodiment, a system includes a
drill string, a drilling fluid unit, a device that allows continuous
circulation of
drilling fluid into the wellbore, and an APD Device in communication with the
drilling fluid to control pressure in the wellbore. The continuous circulation
device is adapted to circulate fluid while making up joints to a drill string,
while
tripping the drill string, and other such activities. In addition to
controlling
wellbore pressure during drilling of the wellbore, the APD Device also
controls
wellbore pressure when drilling is stopped for these activities.
[0019] Using appropriate controls, wellbore pressure can be maintained
below the combined pressure caused by weight of the fluid and pressure
losses created due to circulation of the fluid in the wellbore, at or near a
balanced pressure condition, and at an underbalanced condition.
Additionally, the APD Device can be operated to reduce swab effect in the
wellbore and/or reduce surge effect in the wellbore. Advantageously,
wellbore pressure can be controlled both during the drilling and when the
drilling is stopped without substantially changing density of the fluid. In
some
embodiments, surface control of wellbore pressure is provided by a flow
restriction device such as a choke or valve coupled to the fluid flowing out
of
7
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
the annulus of the wellbore. The flow restriction device selectively creates a
backpressure in the wellbore that can be used to modulate wellbore pressure.
[0020] 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.
8
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
BRIEF DESCRIPTION OF THE DRAWINGS
[0021] 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:
[0022] 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;
[0023] Figure 1 B graphically illustrates the effect of an operating active
pressure differential device upon the pressure at a predetermined wellbore
location;
[0024] Figure 2 is a schematic elevation view of Figure 1A 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 IA;
[0025] 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;
[0026] 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);
[0027] Figures 5A and 5B are schematic illustrations of one embodiment
of an arrangement according to the present invention wherein a turbine drive
is coupled to a centrifugal pump (the APD Device);
[0028] Figures 6 is a graph depicting exemplary dynamic pressure losses
associated with a conventional drilling system and also a system utilizing an
active pressure differential device made in accordance embodiments of the
present invention;
[0029] Figure 7 is a schematic illustration of a continuous circulation
system used in conjunction with an APD Device and flow restriction device
made in accordance with embodiments of the present invention; and
9
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0030] Figure 8 is a graph depicting exemplary dynamic pressure losses
associated with a system utilizing the Fig. 7 system and also the Fig. 7
system when utilizing an active pressure differential device made in
accordance embodiments of the present invention.
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0031] Referring initially to Figure IA, 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 IA 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
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.
[0032] 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 include data and power transmission carriers
such 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.
11
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0033] 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 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.
[0034] 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.
[0035] 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
of the present invention, to manage or control the pressure at the zone 155,
an active pressure differential device ("APD Device") 170 is fluidly 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
"OP" across the device. This controlled pressure drop reduces the pressure
upstream of the APD Device 170 and particularly in zone 155.
12
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0036] 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
IA 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.
[0037] The flow-control devices 174, 175 can also be configured to
selectively 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.
[0038] 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
13
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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.
[0039] Sensors Si., 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_õ communicate with a controller 180 via a
telemetry system (not shown). Using data provided by the sensors SJ_,,, 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).
[0040] When configured for drilling operations, the sensors SJ_,' 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
14
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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.
[0041] 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 S1.,,.
[0042] 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 Sl.,, and control signals
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 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 simplicity 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 memoryunits for storing programmed instructions,
models (which may be interactive models) and data, and other necessary
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
control circuits. The microprocessors control the operations of the various
sensors, provide communication among the downhole sensors and provide
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. In other embodiments, the controller 180 can be a
hydro-mechanical device that incorporates known mechanisms (valves,
biased members, linkages cooperating to actuate tools under, for example,
preset conditions).
[0043] 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.
[0044] 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
16
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
systems and readily adapted to support other well construction, completion,
and work-over activities.
[0045] 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 whether or not the turbine is operating. However, the APD Device
170, when operated creates a differential pressure thereacross.
[0046] 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 IA, 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 location. 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.
[0047] 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
17
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
values that provide an under-balance condition, an at-balance condition or an
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 preselected value or within 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 autonomously control the APD Device or
respond to signals received from another device that may be remotely located
from the APD Device.
[0048] 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 IA shows the APD device 170 at a depth Dl and
a representative location in the wellbore in the vicinity of the well tool 30
at a
lower depth D2. Figure I B provides a depth versus pressure graph having a
first curve C1 representative of a pressure gradient before operation of the
system 100 and a second curve C2 representative of a pressure 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 pressure at depth
Dl and thus shifts the pressure gradient as shown by curve C3, which can
provide the desired predetermined pressure at depth D2. In most instances,
this shift is roughly the pressure drop provided by the APD device 170.
[0049] Figure 2 shows the drill string after it has moved the distance "d"
shown by t, _t2. Since the APD Device 170 is attached to the drill string 121,
the APD Device 170 also is shown moved by the distance d.
18
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0050] 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 IA).
[0051] Referring now to Figures 4A-D, there is schematically illustrated
one arrangement wherein a positive displacement motor/drive 200 is coupled
to a moineau-type pump 220 via a shaft assembly 240. 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
string section 262 on which the bottomhole assembly (not shown) is attached
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 design of
moineau-type pumps and motors are known to one skilled in the art and will
not be discussed in further detail.
[0052] 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 246. As is known, the rotors for
moineau-type motors/pump are subject to eccentric motion during rotation.
Accordingly, the coupling shaft 246 is preferably articulated or formed
sufficiently flexible to absorb this eccentric motion. Alternately or in
combination, the shafts 242, 244 can be configured to flex to accommodate
19
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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, and a
hydrodynamic converters. It should be understood that any number of
arrangements and devices can be used to transfer power, speed, or torque
from the motor 200 to the pump 220. For example, the shaft assembly 240
can utilize a single shaft instead of multiple shafts.
[0053] 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 the drive 200 or pump 220
and operated thereby. For instance, one such comminution device 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 mounted thereon. During
rotation, the eccentric motion of the pump rotor 224 will cause a
corresponding radial motion of the shaft head 274. This radial motion can be
used to resize the cuttings between the rotor and a comminution device
housing 276.
[0054] 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
interior
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.
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0055] Additionally, bypass devices are provided to allow fluid circulation
during tripping of the downhole devices of the system 100 (Fig. 1A), 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.
[0056] The circulation bypass 300 selectively diverts supply fluid into the
annulus 194 (Fig. 1A) 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.
[0057] 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 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 or filters
to selectively convey cuttings or particles entrained in the return fluid that
are
greater than a predetermined size around the APD device. Alternatively, a
21
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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 valve can be configured to
open when 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.
[0058] 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 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.
[0059] During operation, the motor 200 and pump 220 are positioned in a
well bore location such as in 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
22
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
flow goes through the cutting mill 270 and enters the pump 220. In this
embodiment, the controller 180 (Fig. 1A) can be programmed to control the
speed of the motor 200 and thus the operation of the pump 220 (the APD
Device in this instance).
[0060] It should be understood that the above-described arrangement is
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 motor and pump in parallel. For example, the motor
can be concentrically disposed in a pump.
[0061] 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.
[0062] The shaft assembly 390 transmits the power generated by the
turbine 350 to the centrifugal pump 370. One preferred shaft assembiy 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.
[0063] The Figure 5A-B arrangement also includes a supply flow path 410
for channeling supply fluid shown by arrows designated 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
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
23
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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 370. In 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.
[0064] It should be appreciated that a positive displacement pump need
not be matched with only a positive displacement motor, or a centrifugal pump
with only a turbine. In certain applications, operational speed or space
considerations may lend itself to an arrangement wherein a positive
displacement drive can effectively energize a centrifugal pump or a 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. In 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
24
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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.
[0065] In other embodiments, an electrical motor can be used to drive and
control the APD Device. 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.
[0066] 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
embodiments, it should be understood that the present invention is not limited
to any such particular combinations. For example, elements 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
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
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.
[0067] It should be appreciated that the teachings of the present invention
can be advantageously applied to manage wellbore pressure throughout the
well construction process. As is known, formations can have a narrow
"window" within which wellbore pressure must be maintained to prevent a kick
or damage to the formation. As discussed previously, the lower pressure limit
is generally the pore pressure of the formation and the upper limit is the
fracture pressure of the formation. Wellbore pressure should be maintained
within this "window" both when the formation is being drilled and during
periods when drilling has been interrupted. Instances where drilling is
interrupted include periods where joints are added to the drill string and
when
the drill string is tripped into or out of the wellbore. Advantageously,
embodiments of the present invention can be used to control pressure in such
situations.
[0068] An exemplary situation wherein it is desirable to control wellbore
pressure arises while drilling is interrupted in order to add a joint of pipe
to the
drill string. Conventionally, drilling is halted and fluid circulation is
stopped so
that the pipe can be added to the drill string at the rig. Referring now to
Fig.
6, there is shown a graph illustrating changes in wellbore pressure during
such a procedure. The x-axis represents time and the y-axis represents
dynamic pressure loss. For reference, a zero value for dynamic pressure
loss is labeled with numeral 0. A line 700 generally represents wellbore
pressure associated with a conventional drilling system. Interval 702
represent a time period when drilling is halted, interval 704 represent a time
period when drilling is occurring and interval 706 represents transient
conditions. At interval 702, there is no fluid circulation and, therefore, no
dynamic pressure loss. Thus, wellbore pressure at interval 702 is generally
26
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
the hydrostatic pressure of the mud column. At interval 704, a dynamic
pressure loss occurs due to fluid circulation, which manifests itself as an
increase in wellbore pressure. While the interval 706 is shown as smooth
transitions between the upper and lower pressure values, it should be
understood that the cycling of mud pumps and other factors can cause spikes
in pressure. As can be seen, with conventional drilling systems, wellbore
pressure periodically varies between an upper and lower pressure value due
to dynamic pressure losses.
[0069] Advantageously, utilization of an APD Device, such as those
previously described in connection with Figs. IA-5, can increase flexibility
in
selecting operating parameters and improve drilling operations. For instance,
a line 710 represents the pressure associated with a drilling system utilizing
an APD Device (e.g., the APD Device 170 of Fig. IA). The line 710 is shown
offset from the lower pressure values of line 700 merely for clarity. For line
710, interval 712 represents a time period when drilling is halted and
interval
714 represents a time period when drilling is occurring. Intervals of
transient
conditions can exist but have been omitted for simplicity. At interval 712,
there is no fluid circulation and, therefore, no dynamic pressure loss. While
an APD Device could be operating, it assumed that the APD Device is
stopped. Thus, wellbore pressure at interval 712 is generally the hydrostatic
pressure of the mud column. At interval 714, a pressure loss normally occurs
due to fluid circulation, which manifests itself as an increase in wellbore
pressure. However, the APD Device reduces the dynamic pressure loss at
interval 704 of line 700. For simplicity, the pressure differential generated
by
the APD Device is shown as generally equaling the dynamic pressure loss.
The pressure differential, however, can be selected to be a fraction or a
multiple of the dynamic pressure loss. As can be seen, the APD Device can
reduce the magnitude of the pressure changes, which can lead to a more
benign pressure condition in the wellbore when fluid circulation is
periodically
halted.
27
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
[0070] As discussed below, the utility of the present invention extends also
to applications where circulation continues even though drilling is halted.
[0071] Referring now to Fig. 7, there is schematically shown a
conventional drilling rig 730 utilizing a continuous circulation system 732.
The
rig 730 includes known equipment such as a top drive 734, a blowout
preventer (BOP) stack 736, and a fluid circulation system 738, which includes
known equipment such as a pump, mud pit and suitable conduits. A drill
string 740 suspended from the rig 730 drills a wellbore 742 in a formation
736.
The continuous circulation system 732 includes a coupler 733 that is
connected to the top drive 734 and drill string 740. During operation, the top
drive 734 rotates the drill string 740 while the fluid circulation system 738
pumps drilling fluid into the wellbore 742 via the top drive 734 and drill
string
740.
[0072] The coupler 733 maintains fluid circulation through the drill string
740 and to the wellbore 742 even when the top drive 734 is uncoupled from
the drill string 740. The coupler 733 can include suitable rams and isolation
chambers that direct drilling fluid into the drill string while one or more
tubular
joints are made up to the drill string. One suitable coupler is discussed in
"Continuous Circulation Drilling", OTC 14269, J.W. Jenner, et al., which is
hereby incorporated by reference for all purposes. Thus, the continuous
circulation system 732 reduces or eliminates the instances where drilling
fluid
ceases to flow in the wellbore 742. Thus, wellbore pressure does not
normally drop to hydrostatic pressure when the continuous circulation system
732 is in operation.
[0073] It should be understood that the coupler 733 is merely
representative of devices and equipment that convey fluid into the wellbore
while making a connection to the drill string or while tripping the drill
string.
The teachings of the present invention can be advantageously utilized with
any device or system that can convey fluid into the wellbore during activities
28
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
such as tripping and connections interrupt drilling. Moreover, the term
"continuous circulation system" should be understood generically to refer to
one or more devices that can be operated to convey fluid and not any
particular device or system.
[0074] Referring now to Fig. 8, there is shown a graph illustrating the
wellbore pressure changes associated with the Fig. 7 system. The x-axis
represents time and the y-axis represents dynamic pressure loss. A line 750
represents pressure for the Fig. 7 drilling system. Interval 752 represent a
time period when drilling is halted and interval 754 represent a time period
when drilling is occurring. For both intervals 752 and 754, a dynamic
pressure loss occurs due to fluid circulation, which manifests itself as an
increase in wellbore pressure relative to hydrostatic pressure. Thus, the
wellbore pressure is generally the hydrostatic pressure plus ECD for the Fig.
7 system.
[0075] As noted earlier, wellbore pressure should be maintained between
the pore pressure and the fracture pressure. Thus, to prevent a kick, the
wellbore pressure associated with operation of the continuous circulation
system 732 should remain above pore pressure even if fluid circulation is
interrupted. That is, the value of the hydrostatic pressure alone, without
dynamic pressure loss, should be greater than pore pressure to ensure
formation fluids do not flow into the wellbore since dynamic pressure loss
disappears when circulation stops. A conventional circulation system could
utilize a drilling fluid having a high enough mud weight to provide a
hydrostatic
pressure above pore pressure. However, dynamic pressure loss is additive to
hydrostatic pressure. Thus, during circulation, dynamic pressure losses could
cause wellbore pressure to approach or exceed the fracture pressure of the
formation. It should be appreciated that, while the continuous circulation
system can provide enhanced drilling operations, constraints relating to
drilling operating parameters and formation parameters could limit its
applicability in certain situations. Advantageously, use of an APD Device in
29
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
conjunction with the continuous circulation system can mitigate such
constraints.
[0076] Referring to Fig. 7, there is shown an APD Device 760 positioned in
the wellbore in conjunction with the continuous circulation system 732. The
APD Device 760 creates a pressure differential in the wellbore in a manner
previously discussed. Referring now to Fig. 8, this pressure differential
reduces dynamic pressure losses and thereby shifts the line 750 to dashed
line 770. It should be appreciated that this shift can assist in keeping
wellbore
pressure below the fracture pressure of the formation. Moreover, wellbore
pressure can be so maintained even when using a drilling fluid having a mud
weight that provides a hydrostatic pressure greater than pore pressure. Thus,
if operation of the continuous circulation system is interrupted, then
wellbore
pressure drops to hydrostatic pressure, which is higher than pore pressure. If
operation of the APD Device is interrupted, then wellbore pressure increases
to hydrostatic pressure plus ECD. In neither case does welibore pressure fall
below pore pressure. Because the circulating wellbore pressure can be
maintained below fracture pressure while still allowing a hydrostatic pressure
above pore pressure in the event that circulation is stopped, the risk of a
kick
is minimized.
[0077] Furthermore, referring to Fig. 7, a surface flow modulation or
restriction device 780 can be used to control wellbore pressure by controlling
the flow of fluid out of the wellbore 742. The flow restriction device 780,
which
can be a choke or valve, can be actuated to modulate flow of drilling fluid
out
of the annulus of the wellbore 742 and thereby alter wellbore pressure. For
example, a restriction of flow can cause a backpressure in the annulus of the
wellbore 742 that can increase welibore pressure. This backpressure can in
effect reduce the magnitude of the pressure differential caused by the APD
Device 760. Thus, for example, the APD Device 760 can be operated to
provide a generally fixed pressure differential. From the surface, the flow
restriction device 780 can be modulated as desired to increase backpressure
CA 02612111 2007-12-13
WO 2006/138565 PCT/US2006/023495
and thereby set the wellbore pressure. It should be thus appreciated that any
device that can control flow out of the wellbore can be suitable for such a
purpose.
[0078] It should be appreciated that although the above discussion related
to drilling interruptions for adding joints to a drill string, the utility of
the APD
Device in conjunction with a continuous circulation system can also be applied
to instances such as tripping of a drill string into or out of a wellbore. As
noted
earlier with reference to Fig. 6, the transient interval 706 can include
pressure
spikes that temporarily and significantly vary wellbore pressure; e.g., surge
effects can increase wellbore pressure whereas swab effect can decrease
wellbore pressure. Operation of the APD Device during such transient
conditions can mitigate such effects by appropriately controlling wellbore
pressure.
[0079] Furthermore, while utilization of the APD Device was discussed in
the context of the Fig. 7 system, it should be understood that the present
teachings can be applied to any drilling system; including offshore systems,
land-based systems, coiled tubing systems, rotary table driven systems,
tractor based systems, and other systems previously described.
[0080] While the foregoing disclosure is directed to the preferred
embodiments of the invention, various modifications will be apparent to those
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.
31
