Note: Descriptions are shown in the official language in which they were submitted.
CA 02483527 2004-10-01
INSTRUMENTATION FOR A DOWNHOLE DEPLOYMENT VALVE
BACKGROUND OF THE INVENTION
Field of the Invention
The present invention generally relates to methods and apparatus for use in
oil and gas wellbores. More particularly, the invention relates to using
instrumentation to monitor downhole conditions within wellbores. More
particularly,
the invention relates to methods and apparatus for controlling the use of
valves and
other automated downhole tools through the use of instrumentation that can
additionally be used as a relay to the surface. More particularly still, the
invention
relates to the use of deployment valves in wellbores in order to temporarily
isolate
an upper portion of the wellbore from a lower portion thereof.
Description of the Related Art
Oil and gas wells typically begin by drilling a borehole in the earth to some
predetermined depth adjacent a hydrocarbon-bearing formation. After the
borehole
is drilled to a certain depth, steel tubing or casing is typically inserted in
the borehole
to form a wellbore and an annular area between the tubing and the earth is
filled
with cement. The tubing strengthens the borehole and the cement helps to
isolate
areas of the wellbore during hydrocarbon production.
Historically, wells are drilled in an "overbalanced" condition wherein the
wellbore is filled with fluid or mud in order to prevent the inflow of
hydrocarbons until
the well is completed. The overbalanced condition prevents blow outs and keeps
the well controlled. While drilling with weighted fluid provides a safe way to
operate,
there are disadvantages, like the expense of the mud and the damage to
formations
if the column of mud becomes so heavy that the mud enters the formations
adjacent
the wellbore. In order to avoid these problems and to encourage the inflow of
hydrocarbons into the wellbore, underbalanced or near underbalanced drilling
has
become popular in certain instances. Underbalanced drilling involves the
formation
of a wellbore in a state wherein any wellbore fluid provides a pressure lower
than the
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CA 02483527 2008-02-18
natural pressure of formation fluids. In these instances, the fluid is
typically a gas,
like nitrogen and its purpose is limited to carrying out drilling chips
produced by a
rotating drill bit. Since underbalanced well conditions can cause a blow out,
they
must be drilled through some type of pressure device like a rotating drilling
head at
the surface of the well to permit a tubular drill string to be rotated and
lowered
therethrough while retaining a pressure seal around the drill string. Even in
overbalanced wells there is a need to prevent blow outs. In most every
instance,
wells are drilled through blow out preventers in case of a pressure surge.
As the formation and completion of an underbalanced or near underbalanced
well continues, it is often necessary to insert a string of tools into the
wellbore that
cannot be inserted through a rotating drilling head or blow out preventer due
to their
shape and relatively large outer diameter. In these instances, a lubricator
that
consists of a tubular housing tall enough to hold the string of tools is
installed in a
vertical orientation at the top of a wellhead to provide a pressurizable
temporary
housing that avoids downhole pressures. By manipulating valves at the upper
and
lower end of the lubricator, the string of tools can be lowered into a live
well while
keeping the pressure within the well localized. Even a well in an overbalanced
condition can benefit from the use of a lubricator when the string of tools
will not fit
though a blow out preventer. The use of lubricators is well known in the art
and the
forgoing method is more fully explained in U.S. patent number 6,427,776, filed
27
March 2000.
While lubricators are effective in controlling pressure, some strings of tools
are
too long for use with a lubricator. For example, the vertical distance from a
rig floor to
the rig draw works is typically about ninety feet or is limited to that length
of tubular
string that is typically inserted into the well. If a string of tools is
longer than ninety feet,
there is not room between the rig floor and the draw works to accommodate a
lubricator.
In these instances, a down hole deployment valve or DDV can be used to create
a
pressurized housing for the string of tools. Downhole deployment valves are
well known
in the art and one such valve is described in U.S. patent number 6,209,663.
Basically, a
DDV is run into a well as part of a string of casing. The valve is initially
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in an open position with a flapper member in a position whereby the full bore
of the
casing is open to the flow of fluid and the passage of tubular strings and
tools into
and out of the wellbore. In the valve taught in the '663 patent, the valve
includes an
axially moveable sleeve that interferes with and retains the flapper in the
open
position. Additionally, a series of slots and pins permits the valve to be
openable or
closable with pressure but to then remain in that position without pressure
continuously applied thereto. A control line runs from the DDV to the surface
of the
well and is typically hydraulically controlled. With the application of fluid
pressure
through the control line, the DDV can be made to close so that its flapper
seats in a
circular seat formed in the bore of the casing and blocks the flow of fluid
through the
casing. In this manner, a portion of the casing above the DDV is isolated from
a
lower portion of the casing below the DDV.
The DDV is used to install a string of tools in a wellbore as follows: When an
operator wants to install the tool string, the DDV is closed via the control
line by
using hydraulic pressure to close the mechanical valve. Thereafter, with an
upper
portion of the wellbore isolated, a pressure in the upper portion is bled off
to bring
the pressure in the upper portion to a level approximately equal to one
atmosphere.
With the upper portion depressurized, the wellhead can be opened and the
string of
tools run into the upper portion from a surface of the well, typically on a
string of
tubulars. A rotating drilling head or other stripper like device is then
sealed around
the tubular string or movement through a blowout preventer can be re-
established.
In order to reopen the DDV, the upper portion of the wellbore must be
repressurized
in order to permit the downwardly opening flapper member to operate against
the
pressure therebelow. After the upper portion is pressurized to a predetermined
level, the flapper can be opened and locked in place. Now the tool string is
located
in the pressurized wellbore.
Presently there is no instrumentation to know a pressure differential across
the flapper when it is in the closed position. This information is vital for
opening the
flapper without applying excessive force. A rough estimate of pressure
differential is
obtained by calculating fluid pressure below the flapper from wellhead
pressure and
hydrostatic head of fluid above the flapper. Similarly when the hydraulic
pressure is
applied to the mandrel to move it one way or the other, there is no way to
know the
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CA 02483527 2004-10-01
position of the mandrel at any time during that operation. Only when the
mandrel
reaches dead stop, its position is determined by rough measurement of the
fluid
emanating from the return line. This also indicates that the flapper is either
fully
opened or fully closed. The invention described here is intended to take out
the
uncertainty associated with the above measurements.
In addition to monitoring the pressure differential across the flapper and the
position of the flapper in a DDV, it is sometimes desirable to monitor well
conditions
in situ. Recently, technology has enabled well operators to monitor conditions
within
a wellbore by installing monitoring systems downhole. The monitoring systems
permit the operator to monitor multiphase fluid flow, as well as pressure,
seismic
conditions, vibration of downhole components, and temperature during
production of
hydrocarbon fluids. Downhole measurements of pressure, temperature, seismic
conditions, vibration of downhole components, and fluid flow play an important
role
in managing oil and gas or other sub-surface reservoirs.
Historically, monitoring systems have used electronic components to provide
pressure, temperature, flow rate, water fraction, and other formation and
wellbore
parameters on a real-time basis during production operations. These monitoring
systems employ temperature gauges, pressure gauges, acoustic sensors, seismic
sensors, electromagnetic sensors, and other instruments or "sondes", including
those which provide nuclear measurements, disposed within the weilbore. Such
instruments are either battery operated, or are powered by electrical cables
deployed from the surface. The monitoring systems have historically been
configured to provide an electrical line that allows the measuring
instruments, or
sensors, to send measurements to the surface.
Recently, optical sensors have been developed which communicate readings
from the wellbore to optical signal processing equipment located at the
surface.
Optical sensors have been suggested for use to detect seismic information in
real
time below the surface after the well has been drilled for processing into
usable
information. Optical sensors may be disposed along tubing strings such as
production tubing inserted into an inner diameter of a casing string within a
drilled-
out wellbore by use of inserting production tubing with optical sensors
located
thereon. The production tubing is inserted through the inner diameter of the
casing
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strings already disposed within the wellbore after the drilling operation. In
either
instance, an optical line or cable is run from the surface to the optical
sensor
downhole. The optical sensor may be a pressure gauge, temperature gauge,
acoustic sensor, seismic sensor, or other sonde. The optical line transmits
optical
signals to the optical signal processor at the surface.
The optical signal processing equipment includes an excitation light source.
Excitation light may be provided by a broadband light.source, such as a light
emitting diode (LED) located within the optical signal processing equipment.
The
optical signal processing equipment also includes appropriate equipment for
delivery
of signal light to the sensor(s), e.g., Bragg gratings or lasers and couplers
which split
the signal light into more than one leg to deliver to more than one sensor.
Additionally, the optical signal processing equipment includes appropriate
optical
signal analysis equipment for analyzing the return signals from the Bragg
gratings.
The optical line is typically designed so as to deliver pulses or continuous
signals of optic energy from the light source to the optical sensor(s). The
optical
cable is also often designed to withstand the high temperatures and pressures
prevailing within a hydrocarbon wellbore. Preferably, the optical cable
includes an
internal optical fiber which is protected from mechanical and environmental
damage
by a surrounding capillary tube. The capillary tube is made of a high
strength, rigid-
walled, corrosion-resistant material, such as stainless steel. The tube is
attached to
the sensor by appropriate means, such as threads, a weld, or other suitable
method.
The optical fiber contains a light guiding core which guides light along the
fiber. The
core preferably employs one or more Bragg gratings to act as a resonant cavity
and
to also interact with the sonde.
Optical sensors, in addition to monitoring conditions within a drilled-out
well or
a portion of a well during production operations, may also be used to acquire
seismic information from within a formation prior to drilling a well. Initial
seismic data
is generally acquired by performing a seismic survey. A seismic survey maps
the
earth formation in the subsurface of the earth by sending sound energy or
acoustic
waves down into the formation from a seismic source and recording the "echoes"
that return from the rock layers below. The source of the down-going sound
energy
might come from explosions, seismic vibrators on land, or air guns in marine
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, .x
environments. During a seismic survey, the energy source is moved to multiple
preplanned locations on the surface of the earth above the geologic structure
of
interest. Each time the source is activated, it generates a seismic signal
that travels
downward through the earth, is reflected, and, upon its return, is recorded at
a great
many locations on the surface. Multiple energy activation/recording
combinations
are then combined to create a near continuous profile of the subsurface that
can
extend for many miles. In a two-dimensional (2-D) seismic survey, the
recording
locations are generally laid out along a single straight line, whereas in a
three-
dimensional (3-D) survey the recording locations are distributed across the
surface
in a grid pattern. In simplest terms, a 2-D seismic line can be thought of as
giving a
cross sectional picture (vertical slice) of the earth layers as they exist
directly
beneath the recording locations. A 3-D survey produces a data "cube" or volume
that is, at least conceptually, a 3-D picture of the subsurface that lies
beneath the
survey area. A 4-D survey produces a 3-D picture of the subsurface with
respect to
time, where time is the fourth dimension.
After the survey is acquired, the data from the survey is processed to remove
noise or other undesired information. During the computer processing of
seismic
data, estimates of subsurface velocity are routinely generated and near
surface
inhomogeneities are detected and displayed. In some cases, seismic data can be
used to directly estimate rock properties (including permeability and elastic
parameters), water saturation, and hydrocarbon content. Less obviously,
seismic
waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a
host
of others, can often be empirically correlated with known hydrocarbon
occurrences
and that correlation applied to seismic data collected over new exploration
targets.
The procedure for seismic monitoring with optical sensors after the well has
been drilled is the same as above-described in relation to obtaining the
initial
seismic survey, except that more locations are available for locating the
seismic
source and seismic sensor, and the optical information must be transmitted to
the
surface for processing. To monitor seismic conditions within the formation, a
seismic source transmits a signal into the formation, then the signal reflects
from the
formation to the seismic sensor. The seismic source may be located at the
surface
of the wellbore, in an adjacent wellbore, or within the well. The seismic
sensor then
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CA 02483527 2004-10-01
r, . transmits the optical information regarding seismic conditions through an
optical
cable to the surface for processing by a central processing unit or some other
signal
processing device. The processing occurs as described above in relation to the
initial seismic survey. In addition to the seismic source reflecting from the
formation
to the seismic sensor, a signal may be transmitted directly from the seismic
source
to the seismic sensor.
Seismic sensors must detect seismic conditions within the formation to some
level of accuracy to maintain usefulness; therefore, seismic sensors located
on
production tubing have ordinarily been placed in firm contact with the inside
of
casing strings to couple the seismic sensor to the formation, thereby reducing
fluid
attenuation or distortion of the signal and increasing accuracy of the
readings.
Coupling the seismic sensor to the formation from production tubing includes
distance and therefore requires complicated maneuvers and equipment to
accomplish the task.
Although placing the seismic sensor in direct contact with the inside of the
casing string allows more accurate readings than current alternatives because
of its
coupling to the formation, it is desirable to even further increase the
accuracy of the
seismic readings by placing the seismic sensor closer to the formation from
which it
is obtaining measurement. The closer the seismic sensor is to the formation,
the
more accurate the signal obtained. A vibration sensor for example, such as an
accelerometer or geophone, must be placed in direct contact with the formation
to
obtain accurate readings. It is further desirable to decrease the complication
of the
maneuvers and equipment required to couple the seismic sensor to the
formation.
Therefore, it is desirable to place the seismic sensor as close to the
formation as
possible.
While current methods of measuring welibore and formation parameters
using optical sensors allow for temporary measurement of the parameters before
the
drilling and completion operations of the wellbore at the surface and during
production operations on production tubing or other production equipment,
there is a
need to permanently monitor wellbore and formation conditions and parameters
during all wellbore operations, including during the drilling and completion
operations
of the wellbore. It is thus desirable to obtain accurate real time readings of
seismic
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conditions while drilling into the formation. It is further desirable to
permanently
monitor downhole conditions before and after production tubing is inserted
into the
wellbore.
In addition to problems associated with the operation of DDVs, many prior art
downhole measurement systems lack reliable data communication to and from
control units located on the surface. For example, conventional measurement
while
drilling (MWD) tools utilize mud pulse, which works fine with incompressible
drilling
fluids such as a water-based or an oil-based mud, but they do not work when
gasified fluids or gases are used in underbalanced drilling. An alternative to
this is
electromagnetic (EM) telemetry where communication between the MWD tool and
the surface monitoring device is established via electromagnetic waves
traveling
through the formations surrounding the well. However, EM telemetry suffers
from
signal attenuation as it travels through layers of different types of
formations. Any
formation that produces more than minimal loss serves as an EM barrier. In
particular salt domes tend to completely attenuate or moderate the signal.
Some of
the techniques employed to alleviate this problem include running an electric
wire
inside the drill string from the EM tool up to a predetermined depth from
where the
signal can come to the surface via EM waves and placing multiple receivers and
transmitters in the drill string to provide boost to the signal at frequent
intervals.
However, both of these techniques have their own problems and complexities.
Currently, there is no available means to cost efficiently relay signals from
a point
within the well to the surface through a traditional control line.
Expandable Sand Screens (ESS) consist of a slotted steel tube, around
which overlapping layers of filter membrane are attached. The membranes are
protected with a pre-slotted steel shroud forming the outer wall. When
deployed in
the well, ESS looks like a three-layered pipe. Once it is situated in the
well, it is
expanded with a special tool to come in contact with the wellbore wall. The
expander tool includes a body having at least two radially extending members,
each
of which has a roller that when coming into contact with an inner wall of the
ESS,
can expand the wall past its elastic limit. The expander tool operates with
pressurized fluid delivered in a string of tubulars and is more completely
disclosed in
US Patent No. 6,425,444. In this manner ESS supports the wall against
collapsing
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CA 02483527 2007-01-16
into the well, provides a large wellbore size for greater productivity, and
allows free
flow of hydrocarbons into the well while filtering out sand. The expansion
tool
contains rollers supported on pressure-actuated pistons. Fluid pressure in the
tool
determines how far the ESS is expanded. While too much expansion is bad for
both
the ESS and the well, too little expansion does not provide support to the
wellbore
wall. Therefore, monitoring and controlling fluid pressure in the expansion
tool is
very important. Presently fluid pressure is measured with a memory gage, which
of
course provides information after the job has been completed. A real time
measurement is desirable so that fluid pressure can be adjusted during the
operation of the tool if necessary.
There is a need therefore, for a downhole system of instrumentation and
monitoring that can facilitate the operation of downhole tools. There is a
further
need for a system of instrumentation that can facilitate the operation of
downhole
deployment valves. There is yet a further need for downhole instrumentation
apparatus and methods that include sensors to measure downhole conditions like
pressure, temperature, seismic conditions, flow rate, differential pressure,
distributed
temperature, and proximity in order to facilitate the efficient operation of
the
downhole tools. There exists a further need for downhole instrumentation and
circuitry to improve communication with existing expansion tools used with
expandable sand screens and downhole measurement devices such as MWD and
pressure while drilling (PWD) tools. There is a need for downhole
instrumentation
which requires less equipment to couple to the formation to obtain accurate
readings
of wellbore and formation parameters. Finally, there exists a need for the
ability to
measure with substantial accuracy downhole wellbore and formation conditions
during drilling into the formation, as well as a need for the ability to
subsequently
measure downhole conditions after the wellbore is drilled by permanent
monitoring.
SUMMARY OF THE INVENTION
The present invention generally relates to methods and apparatus for
instrumentation associated with a downhole deployment valve (DDV). In one
aspect, a DDV in a casing string is closed in order to isolate an upper
section of a
wellbore from a lower section. Thereafter, a pressure differential above and
below
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CA 02483527 2004-10-01
the closed valve is measured by downhole instrumentation to facilitate the
opening
of the valve. In another aspect, the instrumentation in the DDV includes
different
kinds of sensors placed in the DDV housing for measuring all important
parameters
for safe operation of the DDV, a circuitry for local processing of signal
received from
the sensors, and a transmitter for transmitting the data to a surface control
unit.
In another aspect, the instrumentation associated with the DDV includes an
optical sensor placed in the DDV housing on the casing string for measuring
welibore conditions prior to, during, and after drilling into the formation.
In one
aspect, the present invention includes a method for measuring wellbore or
formation
parameters, comprising placing a downhole tool within a wellbore, the downhole
tool
comprising a casing string, at least a portion of the casing string comprising
a
downhole deployment valve, and an optical sensor disposed on the casing
string,
and lowering a drill string into the wellbore while sensing wellbore or
formation
parameters with the optical sensor. Another aspect of the present invention
provides an apparatus for monitoring conditions within a wellbore or a
formation,
comprising a casing string, at least a portion of the casing string comprising
a
downhole deployment valve for selectively obstructing a fluid path through the
casing string, and at least one optical sensor disposed on the casing string
for
sensing one or more parameters within the wellbore or formation. Yet another
aspect of the present invention provides a method for permanently monitoring
at
least one wellbore or formation parameter, comprising placing a casing string
within
a wellbore, at least a portion of the casing string comprising a downhole
deployment
valve with at least one optical sensor disposed therein, and sensing at least
one
welibore or formation parameter with the optical sensor.
The present invention further includes in another aspect a method for
determining flow characteristics of a fluid flowing through a casing string,
comprising
providing a casing string within a wellbore comprising a downhole deployment
valve
and at least one optical sensor coupled thereto, measuring characteristics of
fluid
flowing through the casing string using the at least one optical sensor, and
determining at least one of a volumetric phase fraction for the fluid or flow
rate for
the fluid based on the measured fluid characteristics. Yet another aspect of
the
present invention includes an apparatus for determining flow characteristics
of a fluid
CA 02483527 2004-10-01
flowing through a casing string in a wellbore, comprising a casing string
comprising
a downhole deployment valve; and at least one optical sensor coupled to the
casing
string for sensing at least one of a volumetric phase fraction of the fluid or
a flow rate
of the fluid through the casing string.
In yet another aspect, the design of circuitry, selection of sensors, and data
communication is not limited to use with and within downhole deployment
valves.
All aspects of downhole instrumentation can be varied and tailored for others
applications such as improving communication between surface units and
measurement while drilling (MWD) tools, pressure while drilling (PWD) tools,
and
expandable sand screens (ESS).
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a section view of a wellbore having a casing string therein, the
casing string including a downhole deployment valve (DDV).
Figure 2A is an enlarged view showing the DDV in greater detail.
Figure 2B is an enlarged view showing the DDV in a closed position.
Figure 3 is a section view of the wellbore showing the DDV in a closed
position.
Figure 4 is a section view of the welibore showing a string of tools inserted
into an upper portion of the wellbore with the DDV in the closed position.
Figure 5 is a section view of the wellbore with the string of tools inserted
and
the DDV opened.
Figure 6 is a schematic diagram of a control system and its relationship to a
well having a DDV or an instrumentation sub that is wired with sensors
Figure 7 is a section view of a wellbore showing the DDV of the present
invention in use with a telemetry tool.
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Figure 8 is a section view of a wellbore having a casing string therein, the
casing string including a downhole deployment valve (DDV) in an open position
with
a seismic sensor disposed on the outside of the casing string.
Figure 9 is a section view of the wellbore showing a drill string inserted
into
an upper portion of the wellbore with the DDV in the closed position.
Figure 10 is a section view of the wellbore with the drill string inserted and
the
DDV opened: A seismic source is located within the drill string.
Figure 11 is a section view of the wellbore with the drill string inserted and
the
DDV opened. A seismic source is located at a surface of the wellbore.
0
Figure 12 is a section view of the wellbore with the drill string inserted and
the
DDV opened. A seismic source is located in a proximate wellbore.
Figure 13 is a cross-sectional view of the DDV of Figures 1-6 with a. flow
meter disposed in the casing string.
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
Placement of one or more seismic sensors on the outside of a casing string
reduces the inherent fluid interference and casing string interference with
signals
which occurs when the seismic sensors are present within the casing string on
the
production tubing and also increases the proximity of the seismic sensors to
the
formation, thus allowing provision of more accurate signals and the
simplifying of
coupling means of the seismic sensors to the formation. Substantially accurate
real
time measurements of seismic conditions and other parameters are thus
advantageously possible during all wellbore operations with the present
invention.
With the present invention, permanent seismic monitoring upon placement of the
casing string within the wellbore allows for accurate measurements of seismic
conditions before and after production tubing is inserted into the wellbore.
Sensors with Downhole Deployment Valves
Figure 1 is a section view of a wellbore 100 with a casing string 102 disposed
therein and held in place by cement 104. The casing string 102 extends from a
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CA 02483527 2004-10-01
surface of the wellbore 100 where a wellhead 106 would typically be located
along
with some type of valve assembly 108 which controls the flow of fluid from the
wellbore 100 and is schematically shown. Disposed within the casing string 102
is a
downhole deployment valve (DDV) 110 that includes a housing 112, a flapper 230
having a hinge 232 at one end, and a valve seat 242 in an inner diameter of
the
housing 112 adjacent the flapper 230. As stated herein, the DDV 110 is an
integral
part of the casing string 102 and is run into the wellbore 100 along with the
casing
string 102 prior to cementing. The housing 112 protects the components of the
DDV
110 from damage during run in and cementing. Arrangement of the flapper 230
allows it to close in an upward fashion wherein pressure in a lower portion
120 of the
wellbore will act to keep the flapper 230 in a closed position. The DDV 110
also
includes a surface monitoring and control unit (SMCU) 107 to permit the
flapper 230
to be opened and closed remotely from the surface of the well. As
schematically
illustrated in Figure 1, the attachments connected to the SMCU 107 include
some
mechanical-type actuator 124 and a control line 126 that can carry hydraulic
fluid
and/or electrical currents. Clamps (not shown) can hold the control line 126
next to
the casing string 102 at regular intervals to protect the control line 126.
Also shown schematically in Figure 1 is an upper sensor 128 placed in an
upper portion 130 of the wellbore and a lower sensor 129 placed in the lower
portion
120 of the wellbore. The upper sensor 128 and the lower sensor 129 can
determine
a fluid pressure within an upper portion 130 and a lower portion 120 of the
wellbore,
respectively. Similar to the upper and lower sensors 128, 129 shown,
additional
sensors (not shown) can be located in the housing 112 of the DDV 110 to
measure
any wellbore condition or parameter such as a position of the sleeve 226, the
presence or absence of a drill string, and wellbore temperature. The
additional
sensors can determine a fluid composition such as an oil to water ratio, an
oil to gas
ratio, or a gas to liquid ratio. Furthermore, the additional sensors can
detect and
measure a seismic pressure wave from a source located within the wellbore,
within
an adjacent wellbore, or at the surface. Therefore, the additional sensors can
provide real time seismic information.
Figure 2A is an enlarged view of a portion of the DDV 110 showing the
flapper 230 and a sleeve 226 that keeps it in an open position. In the
embodiment
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shown, the flapper 230 is initially held in an open position by the sleeve 226
that
extends downward to cover the flapper 230 and to ensure a substantially
unobstructed bore through the DDV 110. A sensor 131 detects an axial position
of
the sleeve 226 as shown in Figure 2A and sends a signal through the control
line
126 to the SMCU 107 that the flapper 230 is completely open. All sensors such
as
the sensors 128, 129, 131 shown in Figure 2A connect by a cable 125 to circuit
boards 132 located downhole in the housing 112 of the DDV 110. Power supply to
the circuit boards 132 and data transfer from the circuit boards 132 to the
SMCU
107 is achieved via an electric conductor in the control line 126. Circuit
boards 132
have free channels for adding new sensors depending on the need. The sensors
128, 129, 131 may be optical sensors, as described below.
Figure 2B is a section view showing the DDV 110 in a closed position. A
flapper engaging end 240 of a valve seat 242 in the housing 112 receives the
flapper 230 as it closes. Once the sleeve 226 axially moves out of the way of
the
flapper 230 and the flapper engaging end 240 of the valve seat 242, a biasing
member 234 biases the flapper 230 against the flapper engaging end 240 of the
valve seat 242. In the embodiment shown, the biasing member 234 is a spring
that
moves the flapper 230 along an axis of a hinge 232 to the closed position.
Common
known methods of axially moving the sleeve 226 include hydraulic pistons (not
shown) that are operated by pressure supplied from the control line 126 and
interactions with the drill string based on rotational or axially movements of
the drill
string. The sensor 131 detects the axial position of the sleeve 226 as it is
being
moved axially within the DDV 110 and sends signals through the control line
126 to
the SMCU 107. Therefore, the SMCU 107 reports on a display a percentage
representing a partially opened or closed position of the flapper 230 based
upon the
position of the sleeve 226.
Figure 3 is a section view showing the wellbore 100 with the DDV 110 in the
closed position. In this position the upper portion 130 of the wellbore 100 is
isolated
from the lower portion 120 and any pressure remaining in the upper portion 130
can
be bled out through the valve assembly 108 at the surface of the well as shown
by
arrows. With the upper portion 130 of the wellbore free of pressure the
wellhead
14
CA 02483527 2004-10-01
106 can be opened for safely performing operations such as inserting or
removing a
string of tools.
Figure 4 is a section view showing the wellbore 100 with the wellhead 106
opened and a string of tools 500 having been instated into the upper portion
130 of
the wellbore. The string of tools 500 can include apparatus such as bits, mud
motors, measurement while drilling devices, rotary steering devices,
perforating
systems, screens, and/or slotted liner systems. These are only some examples
of
tools that can be disposed on a string and instated into a well using the
method and
apparatus of the present invention. Because the height of the upper portion
130 is
greater than the length of the string of tools 500, the string of tools 500
can be
completely contained in the upper portion 130 while the upper portion 130 is
isolated
from the lower portion 120 by the DDV 110 in the closed position. Finally,
Figure 5
is an additional view of the wellbore 100 showing the DDV 110 in the open
position
and the string of tools 500 extending from the upper portion 130 to the lower
portion
120 of the welibore. In the illustration shown, a device (not shown) such as a
stripper or rotating head at the wellhead 106 maintains pressure around the
tool
string 500 as it enters the wellbore 100.
Prior to opening the DDV 110, fluid pressures in the upper portion 130 and
the lower portion 120 of the wellbore 100 at the flapper 230 in the DDV 110
must be
equalized or nearly equalized to effectively and safely open the flapper 230.
Since
the upper portion 130 is opened at the surface in order to insert the tool
string 500, it
will be at or near atmospheric pressure while the lower portion 120 will be at
well
pressure. Using means well known in the art, air or fluid in the top portion
130 is
pressurized mechanically to a level at or near the level of the lower portion
120.
Based on data obtained from sensors 128 and 129 and the SMCU 107, the
pressure conditions and differentials in the upper portion 130 and lower
portion 120
of the wellbore 100 can be accurately equalized prior to opening the DDV 110.
While the instrumentation such as sensors, receivers, and circuits is shown
as an integral part of the housing 112 of the DDV 110 (See Figure 2A) in the
examples, it will be understood that the instrumentation could be located in a
separate "instrumentation sub" located in the casing string. As shown in
Figure 6,
the instrumentation sub can be hard wired to a SMCU 107 in a manner similar to
CA 02483527 2004-10-01
running a hydraulic dual line control (HDLC) cable 126 from the
instrumentation of
the DDV 110. Therefore, the instrumentation sub utilizes sensors, receivers,
and
circuits as described herein without utilizing the other components of the DDV
110
such as a flapper and a valve seat.
Figure 6 is a schematic diagram of a control system and its relationship to a
well having a DDV 110 or an instrumentation sub that is wired with sensors
(also
indicated by 110) as disclosed herein. Shown in Figure 1 is the wellbore
having the
DDV 110 disposed therein with the electronics necessary to operate the sensors
discussed above (see Figure 1).
A conductor embedded in a control line which is shown in Figure 6 as the
hydraulic dual line control (HDLC) cable 126 provides communication between
downhole sensors and/or receivers and a surface monitoring and control unit
(SMCU) 107. The HDLC cable 126 extends from the DDV 110 outside of the casing
string 102 (see Figure 1) containing the DDV 110 to an interface unit 180 of
the
SMCU 107. The SMCU 107 can include a hydraulic pump 185 and a series of
valves utilized in operating the DDV 110 by fluid communication through the
HDLC
126 and in establishing a pressure above the DDV 110 substantially equivalent
to
the pressure below the DDV 110. In addition, the SMCU 107 can include a
programmable logic controller (PLC) based system 181 for monitoring and
controlling each valve and other parameters, circuitry for interfacing with
downhole
electronics, an onboard display 186, and standard RS-232 interfaces (not
shown) for
connecting external devices. In this arrangement, the SMCU 107 outputs
information obtained by the sensors and/or receivers 182 in the wellbore 100
to the
display 186 or to the controls 183. Using the arrangement illustrated, the
pressure
differential between the upper portion and the lower portion of the wellbore
100 can
be monitored and adjusted to an optimum level for opening the valve. In
addition to
pressure information near the DDV 110, the system can also include proximity
sensors that describe the position of the sleeve 226 in the valve that is
responsible
for retaining the valve in the open position. By ensuring that the sleeve 226
is
entirely in the open or the closed position, the valve can be operated more
effectively. The SMCU 107 may further include a power supply 184 for providing
16
CA 02483527 2004-10-01
power to operate the SMCU 107. A separate computing device such as a laptop
187 can optionally be connected to the SMCU 107.
Figure 7 is a section view of a wellbore 100 with a string of tools 700 that
includes a telemetry tool 702 inserted in the wellbore 100. The telemetry tool
702
transmits the readings of instruments to a remote location by means of radio
waves
or other means. In the embodiment shown in Figure 7, the telemetry tool 702
uses
electromagnetic (EM) waves 704 to transmit downhole information to a remote
location, in this case a receiver 706 located in or near a housing of a DDV
110
instead of at a surface of the wellbore. Alternatively, the DDV 110 can be an
instrumentation sub that comprises sensors, receivers, and circuits, but does
not
include the other components of the DDV 110 such as a valve. The EM wave 704
can be any form of electromagnetic radiation such as radio waves, gamma rays,
or
x-rays. The telemetry tool 702 disposed in the tubular string 700 near the bit
707
transmits data related to the location and face angle of the bit 707, hole
inclination,
downhole pressure, and other variables. The receiver 706 converts the EM waves
704 that it receives from the telemetry tool 702 to an electric signal, which
is fed into
a circuit in the DDV 110 via a shortcable 710. The signal travels to the SMCU
via a
conductor in a control line 126. Similarly, an electric signal from the SMCU
can be
sent to the DDV 110 that can then send an EM signal to the telemetry tool 702
in
order to provide two way communication. By using the telemetry tool 702 in
connection with the DDV 110 and its preexisting control line 126 that connects
it to
the SMCU at the surface, the reliability and performance of the telemetry tool
702 is
increased since the EM waves 704 need not be transmitted through formations as
far. Therefore, embodiments of this invention provide communication with
downhole
devices such as telemetry tool 702 that are located below formations
containing an
EM barrier. Examples of downhole tools used with the telemetry tool 702
include a
measurement while drilling (MWD) tool or a pressure while drilling (PWD) tool.
Expandable Sand Screens
Still another use of the apparatus and methods of the present invention relate
to the use of an expandable sand screen or ESS and real time measurement of
pressure required for expanding the ESS. Using the apparatus and methods of
the
current invention with sensors incorporated in an expansion tool and data
17
CA 02483527 2004-10-01
transmitted to a SMCU 107 (see F=igure 6) via a control line connected to a
DDV or
instrumentation sub having circuit boards, sensors, and receivers within,
pressure in
and around the expansion tool can be monitored and adjusted from a surface of
a
wellbore. In operation, the DDV or instrumentation sub receives a signal
similar to
the signal described in Figure 7 from the sensors incorporated in the
expansion tool,
processes the signal with the circuit boards, and sends data relating to
pressure in
and around the expansion tool to the surface through the control line. Based
on the
data received at the surface, an operator can adjust a pressure applied to the
ESS
by changing a fluid pressure supplied to the expansion tool.
Optical Sensors with Downhole Deployment Valves
Figure 8 shows an alternate embodiment of the present invention, depicting a
section view of the casing string 102 disposed within the wellbore 100 and set
therein by cement 104. As in Figure 1, the casing string 102 extends from the
surface of the wellbore 100 from within the wellhead 106 with the valve
assembly
108 for controlling the flow of fluid from the wellbore 100. A downhole
deployment
valve (DDV) 310 is disposed within the casing string 102 and is an integral
part of
the casing string 102. The DDV 310 includes a housing 312, a flapper 430
having a
hinge 432 at one end, and a valve seat 442 formed within the inner diameter of
the
housing 312 adjacent the flapper 430. The flapper 430, hinge 432, and valve
seat
442 operate in the same fashion and possess the same characteristics as the
flapper 230, hinge 232, and valve seat 242 of Figures 1-6, so the above
description
of the operation and characteristics of the components applies equally to the
embodiments of Figures 8-12.
Specifically, the flapper 430 is used to separate the upper portion of the
wellbore 130 from the lower portion of the wellbore 120 at various stages of
the
operation. A sleeve 226 (see Figure 2A) is used to keep the flapper 430 in an
open
position by extending downward to cover the flapper 230 and ensure a
substantially
unobstructed bore through the DDV 310.
Located within the housing 312 of the DDV 310 is an optical sensor 362 for
measuring conditions or parameters within a formation 248 or the welibore,
such as
temperature, pressure, seismic conditions, acoustic conditions, and/or fluid
18
CA 02483527 2007-01-16
composition in the formation 248, including oil to water ratio, oil to gas
ratio, or gas
to liquid ratio. The optical sensor 362 may comprise any suitable type of
optical
sensing elements, such as those described in U.S. Patent Number 6,422,084. For
example, the optical sensor 362 may comprise an optical fiber, having the
reflective
element embedded therein; and a tube, having the optical fiber and the
reflective
element encased therein along a longitudinal axis of the tube, the tube being
fused
to at least a portion of the fiber. Alternatively, the optical sensor 362 may
comprise
a large diameter optical waveguide having an outer cladding and an inner core
disposed therein.
The optical sensor 362 may include a pressure sensor, temperature sensor,
acoustic sensor, seismic sensor, or other sonde or sensor which takes
temperature
or pressure measurements. In one embodiment, the optical sensor 362 is a
seismic
sensor. The seismic sensor 362 detects and measures seismic pressure acoustic
waves 401, 411, 403, 501, 511, 503, 601, 611, 603 in figures 10-12) emitted by
a
seismic source 371, 471, 571 located within the wellbore 100 in a location
such as a
drill string 305 (see Figure 10), at the surface of the wellbore 100 (see
Figure 11), or
in a proximate wellbore 700 (see Figure 12). The operation and construction of
a
Bragg grating sensor which may be utilized with the present invention as the
seismic
sensor is described in commonly-owned U.S. Patent Number 6,072,567, entitled
"Vertical Seismic Profiling System Having Vertical Seismic Profiling Optical
Signal
Processing Equipment and Fiber Bragg Grafting Optical Sensors", issued June 6,
2000.
Construction and operation of an optical sensors suitable for use with the
present invention, in the embodiment of an FBG sensor, is described in the
U.S.
Patent Number 6,597,711 issued on July 22, 2003 and entitled "Bragg Grating-
Based Laser". Each Bragg grating is constructed so as to reflect a particular
wavelength or frequency of light propagating along the core, back in the
direction of
the light source from which it was launched. In particular, the wavelength of
the
Bragg grating is shifted to provide the sensor.
Another suitable type of optical sensor for use with the present invention is
an
FBG-based inferometric sensor. An embodiment of an FBG-based inferometric
19
CA 02483527 2007-01-16
sensor which may be used as the optical sensor 362 of the present invention is
described in U.S. Patent Number 6,175,108 issued on January 16, 2001 and
entitled
"Accelerometer featuring fiber optic bragg grating sensor for providing
multiplexed
multi-axis acceleration sensing". The inferometric sensor includes two FBG
wavelengths separated by a length of fiber. Upon change in the length of the
fiber
between the two wavelengths, a change in arrival time of light reflected from
one
wavelength to the other wavelength is measured. The change in arrival time
indicates the wellbore or formation parameter.
The DDV 310 also includes a surface monitoring and control unit (SMCU) 251
to permit the flapper 430 to be opened and closed remotely from the well
surface.
The SMCU 251 includes attachments of a mechanical-type actuator 324 and a
control line 326 for carrying hydraulic fluid and/or electrical currents. The
SMCU 251
processes and reports on a display seismic information gathered by the seismic
sensor 362.
An optical line 327 is connected at one end to the optical sensor 362 and at
the other end to the SMCU 251, which may include a processing unit for
converting
the signal transmitted through the optical line 327 into meaningful data. The
optical
line 327 is in optical communication with the optical sensor 362 as well as
the SMCU
251 having optical signal processing equipment. One or more control line
protectors
361 are located on the casing string 102 to house and protect the control line
326 as
well as the optical line 327.
Any number of additional seismic sensors 352 (or any other type of optical
sensor such as pressure sensor, temperature sensor, acoustic sensor, etc.),
may be
located on the casing string 102 at intervals above the seismic sensor 362 to
provide
additional locations to which the seismic source 371, 471, 571 may transmit
acoustic
waves (not shown). When using the additional seismic sensors 352, 356, the
optical
line 327 is run through the seismic sensors 352, 356 on its path from the
seismic
sensor 362 to the SMCU 251. Seismic sensor carriers 353, 357 (e.g., metal
tubes)
may be disposed around the seismic sensors 352, 356 to protect the seismic
sensors 353, 356 as well as the control line 326 and optical line 327.
CA 02483527 2004-10-01
Measuring While Drilling
Figure 9 shows the flapper 430 in the closed position, the wellhead 106
opened, and a drill string 305 inserted into the wellbore 100. The drill
string 305 is a
string of tubulars or a string of tools with an earth removal member 306
operatively
attached to its lower end. A flapper engaging end 240 (see Figure 2A) of a
valve
seat 442 in the housing 312 is located opposite the flapper 430. In the
position of
the flapper 430 depicted in Figure 9, a biasing member 234 (see Figure 2A)
biases
the flapper 430 against the valve seat 442. In the embodiment shown in Figure
2A,
the biasing member 234 is a spring.
Figures 10-12 show the DDV 310 in the open position and the drill string 305
extending from the upper portion 130 to the lower portion 120 of the wellbore
100.
Figure 10 shows a seismic source 371 located within the drill string 305, with
acoustic waves 401 and 411 emitted from the seismic source 371 into the
formation
248, then reflected or partially reflected from the formation 248 into the
seismic
sensor 362. Similarly, Figure 11 shows a seismic source 471 located at the
surface
of the wellbore 100, with acoustic waves 501 and 511 emitted from the seismic
source 471 into the formation 248, then reflected or partially reflected from
the
formation 248 into the seismic sensor 362. Figure 12 shows a seismic source
571
located in a nearby wellbore 700, with acoustic waves 601 and 611 also emitted
from the seismic source 571 into the formation 248, then reflected or
partially
reflected from the formation 248 into the seismic sensor 362. In an
alternative
embodiment, the vibration of the drill string 305 itself or another downhole
tool may
act as the seismic source when vibrating against the wellbore or the casing in
the
wellbore. The seismic sources 371, 471, and 571 in Figures 10-12 all transmit
an
acoustic wave 403, 503, or 603 directly to the seismic sensor 362 for
calibration
purposes.
In operation, the casing string 102 with the DDV 310 disposed thereon is
lowered into the drilled-out wellbore 100 through the open wellhead 106 and
cemented therein with cement 104. Initially, the flapper 430 is held in the
open
position by the sleeve 226 (see Figure 2A) to provide an unobstructed wellbore
100
for fluid circulation during run-in of the casing string 102. Figure 8 shows
the casing
21
CA 02483527 2004-10-01
string 102 and the DDV 310 cemented within the wellbore 100 with the flapper
430
in the open position.
When it is desired to run the drill string 305 into the wellbore 100 to drill
to a
further depth within the formation 248, the flapper 430 is closed. The drill
string 305
is inserted into the wellhead 106. Figure 9 shows the flapper valve 430 closed
and
the drill string 305 inserted into the wellbore 100.
The wellhead 106 is then closed to atmospheric pressure from the surface.
The DDV 310 flapper 430 is opened. The drill string 305 is then lowered into
the
lower portion 120 of the wellbore 100 and then further lowered to drill into
the
formation 248. Figures 10-12 depict three different configurations for
transmission
of formation conditions to the surface while the drill string 305 is drilling
into the
formation 248. Formation conditions may also be transmitted to the SMCU 251
before or after the drill string 305 drills into the formation.
In Figure 10, while the drill string 305 is drilling into the formation 248,
the
seismic source 371 transmits acoustic wave 401, which bounces from location
400
in the formation 248 to the seismic sensor 362. Alternatively, the seismic
source
may be activated when the drill string 305 is stationary (not drilling), e.g.,
by forcing
fluid through the drill string through a converter that emits acoustic energy.
The
seismic source 371 also transmits acoustic wave 411, which bounces from
location
410 in the formation 248 to the seismic sensor 362. The seismic source 371
also
transmits acoustic wave 403, which travels directly to the seismic sensor 362.
The
direct transmission of the acoustic wave 403 is necessary to process the
gathered
information and interpret the final image by deriving the distance between the
drill bit
and the seismic sensor 362 plus the travel time to calibrate the acoustic
waves 401
and 411. Because the acoustic waves 401 and 411 must travel to the formation
248, then to the seismic sensor 362, a time delay exists. To offset the
acoustic
waves 401 and 411 with the delay in time, the direct acoustic wave 403 may be
measured with no time delay caused by bouncing off the formation 248. The
additional seismic sensors 352 and 356 on the outside of the casing string 102
may
also receive acoustic waves (not shown) which are bounced from the formation
248
at different locations. Any number of acoustic waves may be emitted by each
seismic source 371, 352, 356 at any angle with respect to the formation 248
and to
22
CA 02483527 2004-10-01
any location within the formation 248. Additional acoustic waves. are shown
emitted
from the seismic source 371 at varying angles to varying locations.
After the acousticwaves 401, 411, and 403 (and any acoustic waves from the
additional seismic sensors 352 and 356) are transmitted into the formation 248
by
the seismic source 371 and then reflected or partially reflected to the
seismic sensor
362, the gathered information is transmitted through the optical cable 327 to
the
SMCU 251. The SMCU 251 processes the information received through the optical
cable 327. The operator may read the information outputted by the SMCU 251 and
adjust the position and drilling direction or drilling trajectory of the drill
string 305, the
composition of the drilling fluid introduced through the drill string 305, and
other
parameters during drilling. In the alternative, the data may be interpreted
off-site at
a data processing center.
Figure 11 shows an alternate embodiment of the present invention. In this
embodiment, vertical seismic profiling ahead of the earth removal member 306
of
the drill string 305 is performed by a seismic source 471 emitted from the
surface of
the wellbore 100, rather than from the earth removal member 306. The seismic
source 471 emits acoustic wave 501, which bounces from the formation 248 at
location 500 to the seismic sensor 362. Also, the seismic source 471 emits
acoustic
wave 511, which bounces from the formation 248 at location 510 to the seismic
sensor 362. As well, the seismic source 471 emits acoustic wave 503, which
travels
through a direct path to the seismic sensor 362 without bouncing from the
formation
248. Acoustic wave 503 is used for calibration purposes, as described above in
relation to acoustic wave 403 of Figure 10. The additional seismic sensors 352
and
356 on the outside of the casing string 102 may also receive acoustic waves
(not
shown) which are bounced from the formation 248 at different, locations. Any
number of acoustic waves may be emitted by each seismic source 471, 352, 356
at
any angle with respect to the formation 248 and to any location within the
formation
248 and transmitted to the seismic sensor 362. The information gathered by the
seismic sensor 362 is transmitted to the SMCU 251 through the optical cable
327,
and the rest of the operation is the same as the operation described in
relation to
Figure 10.
23
CA 02483527 2004-10-01
Figure 12 shows a further alternate embodiment of the present invention.
Here, the seismic source 571 is emitted from a nearby wellbore 700. The
wellbore
700 is shown with casing 602 cemented therein with cement 604. The seismic
source 571 is shown located in the annular area between the casing 602 and the
wellbore 700, but may be located anywhere within the nearby wellbore 700 for
purposes of the present invention. Specifically, the seismic source 571 may be
disposed on a tubular string (not shown) within the nearby wellbore 700, among
other options. Similar to the operation of the embodiment of Figures 10-11,
the
seismic source 571 emits acoustic wave 601 into location 600 in the formation
248,
which bounces off the formation 248 to the seismic sensor 362. The seismic
source
571 emits acoustic wave 611 into location 610 in the formation 248, and the
acoustic
wave 611 bounces off the formation 248 into the seismic sensor 362. The
acoustic
wave 603 is transmitted directly from the seismic source 571 to the seismic
sensor
362 for calibration purposes, as described above in relation to Figures 10-11.
The
additional seismic sensors 352 and 356 on the outside of the casing string 102
may
also receive acoustic waves (not shown) which are bounced from the formation
248
at different locations. Any number of acoustic waves may be emitted by each
seismic source 371, 352, 356 at any angle with respect to the formation 248
and to
any location within the formation 248 for receiving by the seismic sensor 362.
The
information gathered by the seismic sensor 362 is transmitted to the SMCU 251
through the optical cable 327, and the rest of the operation is the same as
the
operation described in relation to Figure 10.
In another aspect of the present invention, optical sensors may be utilized in
embodiments of DDVs shown in Figures 1-6 to measure the differential pressure
across the downhole deployment valve. An optical sensor may also be used to
measure the position of the flapper valve of the downhole deployment valve. An
FBG may be coupled with the flapper via a strain-inducing member such that
movement of the flapper valve induces a strain on the FBG. The strain of the
FBG
may result in a change in the FBG wavelength indicative of the position of the
flapper valve. The optical seismic, pressure, temperature, or acoustic sensors
shown and described in relation to Figures 8-12 may also be utilized in
combination
with the optical sensors utilized in Figures 1-6 to measure differential
pressure
across the DDV.
24
CA 02483527 2004-10-01
Although the above descriptions of Figures 8-12 contemplated the use of a
seismic sensor 362 within the DDV 310, an optical pressure sensor (not shown)
or
temperature sensor (not shown) may also be deployed with the DDV 310 of the
above figures to measure temperature or pressure within the formation 248 or
the
wellbore 100. The present invention may be utilized in vertical or crosswell
seismic
profiling in 2D, 3D, or 4D, or continuous seismic monitoring, such as
microseismic
monitoring. VSP may be accomplished when the seismic source is located at the
surface by moving the seismic source to accumulate the full image of the
formation.
Crosswell seismic profiling may be accomplished when the seismic source is
located
in an adjacent wellbore by moving the seismic source to accumulate a full
image of
the formation.
The embodiments depicted in Figures 8-12 may also be useful to calibrate
surface seismic data after the casing string has been placed at a known depth
within
the wellbore. Furthermore, as described above, the present invention provides
real
time seismic data while drilling into the formation, including imaging ahead
of the drill
string and pore pressure prediction. The measurements from the acoustic waves
sent to the SMCU may be utilized in geosteering to correlate the seismic image
and
update the seismic data initially obtained by the seismic survey to current
conditions
while drilling into the formation. Geosteering allows the operator to
determine in
what direction to steer the drill string to drill to the targeted portion of
the formation.
The information gathered by the seismic sensor may be placed into models to
determine formation conditions in real time.
The above embodiments are also useful in performing acoustic monitoring
while drilling into the formation, including monitoring the vibration of the
drill string
and/or the earth removal member against the casing in the wellbore, along with
monitoring the vibration of other tools and downhole components against the
casing
within the wellbore, monitoring the acoustics of drilling fluids introduced
into the drill
string while drilling into the formation, and monitoring acoustics within an
adjacent
wellbore.
Embodiments of the present invention are not only useful in obtaining seismic
data in real time, but may also provide monitoring of seismic conditions after
the well
has been drilled, including but not limited to microseismic monitoring and
other
CA 02483527 2004-10-01
= t acoustic monitoring during production of the hydrocarbons within the well.
Microseismic monitoring allows the operator to detect, evaluate, and locate
small
fracture events related to production operations, such as those caused by the
movement of hydrocarbon fluids or by the subsidence or compaction of the
formation. After the well has been drilled, the present invention may also be
utilized
to obtain seismic information from an adjacent wellbore.
Flow Meter
Other parameters may be measured using optical sensors according to the
present invention. A flow meter 875 may be included as part of the casing
string
102 to measure volumetric fractions of individual phases of a multiphase
mixture
flowing through the casing string 102, as well as to measure flow rates of
components in the multiphase mixture. Obtaining these measurements allows
monitoring of the substances being removed from the wellbore while drilling,
as
described below.
Specifically, when utilizing optical sensors as the upper and lower sensors
128 and 129 and additional sensors (not shown) to measure the position of
sleeve
226 or other wellbore parameters as described in relation to Figures 1-6, a
flow
meter may be disposed within the casing string 102 above or below the DDV 110.
In Figure 13, the flow meter 875 is shown above the DDV 110. The DDV 110 has
the same components and operates in the same manner as described above in
relation to Figures 1-6, so like components are labeled with like numbers to
Figures
1-6. The casing string 102, which has an inner surface 806 and an outer
surface
807, is shown set within a wellbore 100 drilled out of a formation 815. The
casing
string 102 is set within the wellbore 100 by cement 104.
The wellhead 106 with the valve assembly 108 may be located at a surface
865 of the wellbore 100. Various tools, including a drill string 880 may be
lowered
through the wellhead 106. The drill string 880 includes a tubular 882 having
an
earth removal member 881 attached to its lower end. The earth removal member
881 has passages 883 and 884 therethrough for use in circulating drilling
fluid Fl
while drilling into the formation 815 (see below).
26
CA 02483527 2008-02-18
A SMCU 860, which is the same as the SMCU 251 of Figures 8-12 as well as
the SMCU 107 of Figures 1-7, is also present at the surface 565. The SMCU 860
may include a light source, delivery equipment, and logic circuitry, including
optical
signal processing, as described above. An optical cable 855, which is
substantially
the same as the optical line 327 of Figures 8-12, is connected at one end to
the
SMCU 860.
The flow meter 875 may be substantially the same as the flow meter
described in co-pending U.S. Patent Number 6,945,095, entitled "Non-Intrusive
Multiphase Flow Meter" and filed on January 21, 2003. Other flow meters may
also
be useful with the present invention. The flow meter 875 allows volumetric
fractions
of individual phases of a multiphase mixture flowing through the casing string
102,
as well as flow rates of individual phases of the multiphase mixture, to be
found.
The volumetric fractions are determined by using a mixture density and speed
of
sound of the mixture. The mixture density may be determined by direct
measurement from a densitometer or based on a measured pressure difference
between two vertically displaced measurement points (shown as P1 and P2) and a
measured bulk velocity of the mixture, as described in the above patent
application.
Various equations are utilized to calculate flow rate and/or component
fractions of
the fluid flowing through the casing string 102 using the above parameters, as
disclosed and described in the above application.
In one embodiment, the flow meter 875 may include a velocity sensor 891
and speed of sound sensor 892 for measuring bulk velocity and speed of sound
of
the fluid, respectively, up through the inner surface 806 of the casing string
102,
which parameters are used in equations to calculate flow rate and/or phase
fractions
of the fluid. As illustrated, the sensors 891 and 892 may be integrated in
single flow
sensor assembly (FSA) 893. In the alternative, sensors 891 and 892 may be
separate sensors. The velocity sensor 891 and speed of sound sensor 892 of FSA
893 may be similar to those described in commonly-owned U.S. Patent Number
6,354,147, entitled "Fluid Parameter Measurement in Pipes Using Acoustic
Pressures", and issued March 12, 2002.
27
CA 02483527 2008-02-18
The flow meter 875 may also include combination pressure and temperature
(P/T) sensors 814 and 816 around the outer surface 807 of the casing string
102,
the sensors 814 and 816 similar to those described in detail in commonly-owned
U.S. Patent Number 5,892,860, entitled "Multi-Parameter Fiber Optic Sensor For
Use In Harsh Environments", issued April 6, 1999. In the alternative, the
pressure
and temperature sensors may be separate from one another. Further, for some
embodiments, the flow meter 875 may utilize an optical differential pressure
sensor
(not shown). The sensors 891, 892, 814, and/or 816 may be attached to the
casing
string 102 using the methods and apparatus described in relation to attaching
the
sensors 30, 130, 230, 330, 430 to the casing strings 5, 105, 205, 305, 405 of
Figures
1-5 of co-pending U.S. Patent Number 7,219,729 having Attorney Docket Number
WEAT/0438 and entitled "Permanent Downhole Deployment of Optical Sensors",
filed on the same day as the current application.
The optical cable 855, as described above in relation to Figures 8-12, may
include one or more optical fibers to communicate with the sensors 891, 892,
814,
816. Depending on a specific arrangement, the optical sensors 891, 892, 814,
816
may be distributed on a common one of the fibers or distributed among multiple
fibers. The fibers may be connected to other sensors (e.g., further downhole),
terminated, or connected back to the SMCU 860. The flow meter 875 may also
include any suitable combination of peripheral elements (e.g., optical cable
connectors, splitters, etc.) well known in the art for coupling the fibers.
Further, the
fibers may be encased in protective coatings, and may be deployed in fiber
delivery
equipment, as is also well known in the art.
Embodiments of the flow meter 875 may include various arrangements of
pressure sensors, temperature sensors, velocity sensors, and speed of sound
sensors. Accordingly, the flow meter 875 may include any suitable arrangement
of
sensors to measure differential pressure, temperature, bulk velocity of the
mixture,
and speed of sound in the mixture. The methods and apparatus described herein
may be applied to measure individual component fractions and flow rates of a
wide
variety of fluid mixtures in a wide variety of applications. Multiple flow
meters 875
28
CA 02483527 2008-02-18
may be employed along the casing string 102 to measure the flow rate and/or
phase
fractions at various locations along the casing string 102.
For some embodiments, a conventional densitometer (e.g., a nuclear fluid
densitometer) may be used to measure mixture density as illustrated in Figure
2B of
the US Patent No. 6,945,095 and described therein. However, for other
embodiments, mixture density may be determined based on a measured
differential
pressure between two vertically displaced measurement points and a bulk
velocity of
the fluid mixture, also described in US Patent No, 6,945,095.
In use, the flow meter 875 is placed within the casing string 102, e.g., by
threaded connection to other casing sections. The wellbore 100 is drilled to a
first
depth with a drill string (not shown). The drill string is then removed. The
casing
string 102 is then lowered into the drilled-out wellbore 100. The cement 104
is
introduced into the inner diameter of the casing string 102, then flows out
through
the lower end of the casing string 102 and up through the annulus between the
outer
surface 807 of the casing string 102 and the inner diameter of the wellbore
100. The
cement 104 is allowed to cure at hydrostatic conditions to set the casing
string 102
permanently within the wellbore 100.
From this point on, the flow meter 875 is permanently installed within the
wellbore 100 with the casing string 102 and is capable of measuring fluid flow
and
component fractions present in the fluid flowing through the inner diameter of
the
casing string 102 during wellbore operations. Simultaneously, the DDV 110
operates as described above to open and close when the drill string 880 acts
as the
tool 500 (see Figures 1-6) which is inserted within the wellbore 100, and the
optical
sensors 128, 129, 131 may sense wellbore and formation conditions as well as
position of the sleeve 226, as described above in relation to Figures 1-6.
Often, the wellbore 100 is drilled to a second depth within the formation 815.
As described above in relation to Figure 5, the drill string 880 of Figure 13
is inserted
into the casing string 102 and used to drill into the formation 815 to a
second depth.
During the drilling process, it is customary to introduce drilling fluid Fl
into the drill
string 880. The drilling fluid Fl flows down through the drill string 880, as
indicated
29
CA 02483527 2008-02-18
by the arrows labeled F1, then out through the passages 883 and 884. After
exiting
the passages 883 and 884, the drilling fluid Fl mingles with the particulate
matter
including cuttings produced from drilling into the earth formation 815, then
carries
the particulate matter including cuttings to the surface 865 by the fluid
mixture F2,
which includes the drilling fluid Fl and the particulate matter. The fluid
mixture F2
flows to the surface 865 through an annulus between the outer diameter of the
drill
string 880 and the inner surface 806 of the casing string 102, as indicated by
the
arrows labeled F2. The drilling fluid Fl is ordinarily introduced in order to
clear the
wellbore 100 of the cuttings and to ease the path of the drill string 880
through the
formation 815 during the drilling process.
While the fluid mixture F2 is circulating up through the annulus between the
drill string 880 and the casing string 102, the flow meter 875 may be used to
measure the flow rate of the fluid mixture F2 in real time. Furthermore, the
flow
meter 875 may be utilized to measure in real time the component fractions of
oil,
water, mud, gas, and/or particulate matter including cuttings, flowing up
through the
annulus in the fluid mixture F2. Specifically, the optical sensors 891, 892,
814, and
816 send the measured wellbore parameters up through the optical cable 855 to
the
SMCU 860. The optical signal processing portion of the SMCU 860 calculates the
flow rate and component fractions of the fluid mixture F2, as described in US
Patent
No. 6,945,095 utilizing the equations and algorithms disclosed in the above-
referenced application. This process is repeated for additional drill strings
and
casing strings.
By utilizing the flow meter 875 to obtain real-time measurements while
drilling, the
composition of the drilling fluid Fl may be altered to optimize drilling
conditions, and
the flow rate of the drilling fluid Fl may be adjusted to provide the desired
composition and/or flow rate of the fluid mixture F2. Additionally, the real-
time
measurements while drilling may prove helpful in indicating the amount of
cuttings
making it to the surface 865 of the wellbore 100, specifically by measuring
the
amount of cuttings present in the fluid mixture F2 while it is flowing up
through the
annulus using the flow meter 875, then measuring the amount of cuttings
present in
the fluid exiting to the surface 865. The composition and/or flow rate of the
drilling
fluid Fl may then be adjusted during the drilling process to ensure, for
CA 02483527 2004-10-01
example, that the cuttings do not accumulate within the wellbore 100 and
hinder the
path of the drill string 880 through the formation 815.
While the sensors 891, 892, 814, 816 are preferably disposed around the
outer surface 807 of the casing string 102, it is within the scope of the
invention for
one or more of the sensors 891, 892, 814, 816 to be located around the inner
surface of the casing string 102 or embedded within the casing string 102. In
an
application of the present invention, temperature, pressure, and flow rate
measurements obtained by the above embodiments may be utilized to determine
when an underbalanced condition is reached within the wellbore 100.
While the foregoing is directed to embodiments of the present invention, other
and further embodiments of the invention may be devised without departing from
the
basic scope thereof, and the scope thereof is determined by the claims that
follow.
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