Note: Descriptions are shown in the official language in which they were submitted.
CA 02471867 2004-07-14
APPARATUS FOR THE REMOTE MEASUREMENT OF
PHYSICAL PARAMETERS
The invention relations to an apparatus for the remove measurement of physical
parameters in which the advantages of optical fibre cables and optical fibre
sensors are
exploited for use within the oil industry. The invention has important
applications for
monitoring oil and gas reservoirs, for stack monitoring and monitoring within
refineries.
The present divisional application is divided out of parent application Serial
No. 2,201,384 filed on March 27, 1997.
The invention of the parent application relates to an apparatus for the remote
control of physical parameters and a method of installation of a cable in a
conduit
located in a remote location.
The invention of the present divisional application relates to a method and an
apparatus for monitoring the condition of a downhole pump.
As oil and gas reserves have been consumed over the years, the extraction of
the
oil and gas has become increasingly more difficult under more demanding
conditions.
Accordingly, there is a need for the reserves to be monitored to a higher
quality than
hitherto. The potential payback is reducing operating costs and increasing the
yield from
individual reservoirs. The invention also impacts on operational and
environmental
safety.
GB-A-2284257 relates to apparatus for the remote measurement of physical
parameters. Experience over many installations has shown that the technique is
not
always reliable especially when deploying optical fibre sensors through steel
hydraulic
control lines in oil wells where the steel hydraulic control lines contain
many bends and
curves. The problem is that optical fibre cables can become stalled in the
control line
which can lead to tangling and possible destruction of the optical fibre cable
in the
hydraulic control line.
It would be desirable to improve on known apparatus by improving the
reliability
of the apparatus needed to install and retrieve an optical fibre sensor for
the
measurement of physical parameters.
CA 02471867 2004-07-14
la
In accordance with one aspect of the parent application, there is provided a
method of installing at least one cable in a conduit adapted to be located in
a remote
location, comprising: deploying a conduit in a remote location; providing at
least one
cable; propelling a first fluid through the conduit to force at least portions
of the at least
one cable through the conduit; and replacing the first fluid with a second
fluid for the
long-term preservation of the at least one cable.
In accordance with another aspect of the parent application, there is provided
a
method of installing at least one cable in a conduit adapted to be located in
a wellbore,
comprising: deploying a conduit in a wellbore; providing at least one fiber
optic cable,
the at least one fiber optic cable being capable of sensing a characteristic;
propelling a
first fluid through the conduit to force at least portions of the at least one
cable through
the conduit; and replacing the first fluid with a second fluid for the long-
term
preservation of the at least one fiber optic cable.
In accordance with another aspect of the parent application, there is provided
a
well completion adapted to be disposed in a subterranean wellbore, comprising:
a
conduit located in the wellbore; at least one cable at least portions of which
are adapted
to be housed within the conduit; wherein a first fluid is propelled through
the conduit to
force at least portions of the at least one cable through the conduit; and
wherein the first
fluid is replaced with a second fluid for the long-term preservation of the at
least one
cable.
In accordance with another aspect of the parent application, there is provided
an
apparatus for the remote measurement of physical parameters, comprising: an
optical
fiber cable adapted to measure a physical parameter in a remote location; a
conduit
extending to the remote location and configured to accommodate the optical
fiber cable;
a cable installation mechanism configured to install the optical fiber cable
through the
conduit and place the optical fiber cable at the remote location, the cable
installation
mechanism including means for propelling a fluid along the conduit; and a seal
between
the optical fiber cable and the conduit.
CA 02471867 2004-07-14
lb
In accordance with another aspect of the parent application, there is provided
a
method of installing a cable at a remote location, comprising: providing an
optical fiber
cable adapted to measure a physical parameter in a remote location; installing
the optical
fiber cable through a conduit to a remote location by using a cable
installation
mechanism which propels a fluid along the conduit; and sealing between the
optical fiber
cable and the conduit.
In accordance with another aspect of the parent application, there is provided
a
method of installing a cable in a wellbore, comprising: providing an optical
fiber cable
adapted to measure a physical parameter in a wellbore; installing the optical
fiber cable
through a conduit by using a cable installation mechanism which propels a
fluid along
the conduit; and extending the conduit into the wellbore after the installing
step.
In accordance with another aspect of the parent application, there is provided
an
apparatus for the measurement of physical parameters in a wellbore,
comprising: a
coated optical fiber cable adapted to measure a physical parameter in the
wellbore;
interrogation means functionally connected to the optical fiber cable; a
conduit
configured to accommodate the optical fiber cable and extending to a
measurement
location in the wellbore; and cable installation means configured to install
the optical
fiber cable through the conduit and place the optical fiber cable at the
measurement
location, the cable installation means including means for propelling a fluid
along the
conduit.
In accordance with another aspect of the parent application, there is provided
an
apparatus for the measurement of physical parameters in a wellbore,
comprising: an
optical fiber cable adapted to measure a physical parameter in a wellbore; a
conduit
configured to accommodate the optical fiber cable; a coiled tubing adapted to
be
deployed into the wellbore and containing the conduit; and a cable
installation
mechanism configured to install the optical fiber cable through the conduit,
the cable
installation mechanism including means for propelling a fluid along the
conduit.
In accordance with one aspect of the divisional application, there is provided
a
method for monitoring the condition of a downhole pump in fluid communication
with a
production tubing, comprising: providing a conduit having a distributed
temperature
sensing optical fiber cable disposed therein; winding a portion of the conduit
at least once
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lc
around the production tubing proximate the location of the pump; and using the
distributed temperature sensing optical fiber cable to monitor a change in
temperature of
the conduit as a function of the condition of the downhole pump.
In accordance with another aspect of the divisional application, there is
provided
an apparatus for monitoring the condition of a downhole pump in fluid
communication
with a production tubing, comprising: a conduit wound at least once around the
production
tubing proximate the location of the downhole pump; a distributed temperature
sensing
optical fiber cable disposed within the conduit; wherein the distributed
temperature
measurement of the optical fiber cable is indicative of the condition of the
downhole
pump.
According to a non-limiting embodiment, there is provided apparatus for the
remote measurement of physical parameters, which apparatus comprises sensing
means
for sensing one or more physical parameters, interrogation means for
interrogating the
sensing means and making a measurement, a
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cable for extending between the sensing means and the interrogation means, a
conduit
for extending to a measurement location and which is of such a cross-sectional
size
that it is able to accept the cable and the sensing means, and cable
installation means
for instafling the sensing and the cable through the conduit and for placing
the
sensing means at the measurement location, the cable installation means being
such that
it inchides means for propelling a fluid along the conduit, and the conduit
being such
that it contains a lead-in section for providing sufficient fluid drag on the
cable as it
enters the conduit from the cable installation means to ensure that the
sensing means is
able to be transported through the conduit.
The sensing means may be one or more optical fibre sensors. These optical
fibre sensors may be sensors for measuring temperature, distn'buted
temperature,
pressure, acoustic energy, electric current, magnetic field, electric field,
or a
combination thereof.
The interrogation means may be ~ntation electronics.
The interrogation means may be an electro-optic electronic readout system
suitable for interrogating the appropriate optical fibre sensors and may
include one or
more optical fibre amplifiers.
The cable may be one or more optical fibre cables. '
The means for propelling a fluid may be a hydraulic pump.
The means for propelling a fluid may be a gas bottle or a compressor.
The conduit may be high-pressure tubing with an inside diameter and pressure
rating to make it suitable for deploying sensors to remote locations.
The conduit may be steel hydraulic control line commonly used in the oil and
gas industry having an external diameter of 1/8" to'/." (3mm to l9mm).
Alternatively,
the conduit may be coiled tubing commonly used in the oil and gas industry
having an
external diameter of'/." to 2" (l9mrn to SOmm) or greater:
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3
The lead-in section should be long enough and straight enough so that fluid
flow is sufficient to cause the cable and sensing means to be propelled into
a>~
continue to be propelled into the conduit while the fluid is flowing, without
causing the
cable to stall in the lead-in section.
The lead-in section preferably does not contain substantial bemls having bend
radii less than 100 times the internal cmss-sectional radius of the lead-in
section.
The lead-in section preferably does not contain bends which cause the cable,
when tensioned in the conduit to engage multiple surfaces of the conduit and
in which
at least two of these surfaces are separated by a dista~e less than 10 times
the internal
cross-sectional dia~ter of the conduit.
The lead-in section is preferably a substantially straight section of tubing
which
is at least 2 meters long. The tubing may be a straight section of the
conduit.
The lead-in section is preferably of such a design that if the conduit is
detached
from the lead-in section, and transport of the cable through the lead-in
section
commenced using the cable installation means, then the cable will continue to
be
transported through the lead-in section if a tensile load of up to 1 Newton is
applied to
the cable at the exit of the lead-in section for more than o~ minute, and
where the
cable will start to transport again if the motion of the cable is stalled at
the exit of the
lead-in section for more than two seconds.
The interrogation means need not be connected to the sensing means while the
sensing means is transported through the conduit to the measurement location.
In
many instances it is preferable to remove the cable installation means and the
lead-in
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4
section once the sensing means is located at the measurement location, to form
a seal
around the cable where it enters or exits from the conduit, and then to
connect the
cable to the interrogation means with a separate cable specially designed for
surface
cabling.
In sorry instances, it may be preferable to pump the sensing means and the
cable through the conduit, and then to place the conduit such that the sensing
means is
located at the measurement location. An example is where the sensing means and
cable is pumped into the conduit and then the conduit is subsequently lowered
into an
oil well in order to take a measurement. The conduit can then be removed from
the oil
well and lowered into one or more oil wells to repeat the measurement. It will
be
appreciated that it may be preferable to weight the conduit prior to lowering
it into the
oil well. The conduit when inserted into the oil well may be configured as a
single
channel from the surface into the oil well, or may be configured such that it
extends
into the oil well and then returns back to the surface again.
In a first embodiment, there is provided apparatus for the
remote measurement of physical parameters, in which the cable installation
means
includes a lead element attached to the sensing means which ensures that the
lead
element is always able to contribute a net propelling force to avoid the
sensing means
from stalling or to overcome a temporary stalling of the sensing means while
the fluid
is flowing along the conduit. This is particularly advantageous when the
sensor
element is relatively stiff and cannot reliably circumvent bends in the
conduit without
touching the side walls of the conduit.
In a second embodiment, there is provided apparatus for the
remote measurement of physical parameters, which apparatus includes a first
port
where fluid enters into the conduit, and first orifice means through which the
cable is
able to be progressively pulled while deploying the sensing means, and in
which the
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S
orifice means is such that sufficient fluid flows through the conduit in order
to
transport the sensing means to the measurement location.
The first orifice means may comprise a defortnable insert which can be
deform~l in order to provide a close fit around the cable as it is being
pulled through
the deformable insert. Such an awangement is commonly referred to as a stuffng
box,
and is common in the oil industry in slickline operations.
The first orifice means may comprise a wireline injector suitably modified for
small diameter cables such as optical fibre cables. Care must be taken with
such an
injector not to use grease which may coat the fibre and cause it to stick to
the wall of
the conduit.
The first orifice means may include a capillary, preferably of a material such
as
stannless steel, connected to the lead-in section through which the cable is
able to be
progressively pulled while deploying the sensing means. The capillary may
preferably
be designed to form a close fit around the cable to prevent excessive fluid
escaping
through the capillary. Its entry may preferably be shaped so as not to damage
the
cable.
The lead-in section may include a diameter restriction in order to reduce the
pressure of the fluid at the end of the capillary where the cable enters into
the lead-in
section. The advantage is to reduce the backward force on the cable, to
increase the
forward drag on the cable at the capillary exit, and to reduce fluid loss
through the
capillary. The diameter restriction is preferably designed with an
adiabatically reducing
taper followed by an adiabatically increasing taper in order to minimise the
overall
pressure loss in the lead-in section as measured after and before the diameter
restriction means.
In a third embodiment, there is provided apparatus for the
remote measurement of physical parameters, which apparatus includes an exit
port at
CA 02471867 2004-07-14
6
the end of the lead-in section in order to increase the rate that fluid flows
in the lead-in
section and thus increase the fluid drag on the cable in the lead-in section.
The exit port may include a valve which is preferably closed once the sensing
means has reached it.
The exit port may include a viscojet designed to ensure that the fluid flowing
through the exit port does not create excessive turbulence in the conduit.
In a fourth embodiment, there is provided apparatus for the
remote measurement of physical parameters, which apparatus includes a first
port
where the fluid enters into the lead-in section, a first orifice means and a
second orifice
means through which the cable is able to be progressively pulled while
deploying the
sensing means, and a second port for reducing the fluid flowing through the
second
orifice means, in which the design of the first and second orifice means is
such that
sufficient fluid flows through the conduit in order to hansport the sensing
means to the
measurement location.
The second port may be connected to the means for propelling the fluid along
the conduit. Such an arrangement is usefi~l in oil well applications for
reducing the risk
of gases such as light hydrocarbons or hydrogen sulphide or other poisonous
gases
escaping from the conduit through the second orifice means.
The apparatus may include a plurality of orifice means, in which each orifice
means contains at least one port for progressively reducing the fluid flowing
through
each orifice means from the conduit. The fluid flowing through each port may
be
regulated using valves or chokes.
According to a fifth embodiment, there is provided apparatus
for the remote measurement of physical parameters, which apparatus includes a
first
port where the fluid enters into the conduit, a first orifice means through
which the
cable may be progressively pulled while deploying tl~e sensing means, and in
which the
CA 02471867 2004-07-14
7
cable installation means includes pay out means for controlling the rate at
which the
cable deploys.
The pay out means is preferably controlled to limit the rate at which the
cable is
deployed, and to make the rate at which the cable is deployed independent of
the fluid
flow rate. It is important for reliable deployment to ensure that the rate at
which the
cable is deployed into the lead-in section is no greater than the rate at
which the cable
is being transported in subsequent sections of the conduit. Failure to observe
this
condition can lead to the cable "piling up" within the conduit - a condition
which is
difficult to cure.
The pay out means may include a wheel assembly for progressively pulling the
cable through the first orifice means.
The pay out means may alternatively be located on the other side of the first
orifice means and may limit the rate at which the cable is pulled through the
first orifice
means.
According to a sixth embodiment, there is provided apparatus
for the remote measurement of physical parameters, in which the cable
installation
means includes a first port where the fluid enters into the conduit, and a
sealed
container for holding the sensing and the cable prior to pumping the sensing
means to the measurement location.
CA 02471867 2004-07-14
Embodiments will now be described solely by way of example and with reference
to the accompanying drawing in which:
Figure 1 is a diagram of an embodiment;
Figure 2 is a diagram of an embodiment in which the sensing means includes a
lead element;
Figure 3 is a diagram of an embodiment in which the sensing means includes a
lead element;
Figure 4 is a diagram of an embodiment in which the apparatus includes a first
port and a first orifice means;
Figure 5 is a diagram of an embodiment in which the first orifice means is a
stuffing box;
Figure 6 is a diagram of an embodiment in which the first orifice means
includes
a capillary;
Figure 7 is a diagram of an embodiment in which the apparatus includes an exit
port at the end of the lead-in section means;
Figure 8 is a diagram of an embodiment in which the apparatus includes first
and
second orifice means;
Figure 9 is a diagram of an embodiment in which the apparatus includes a
second
port means;
Figure 10 is a diagram of an embodiment in which the apparatus includes a pay
out means;
Figure 11 is a diagram of an embodiment in which the apparatus includes a pay
out means;
Figure 12 is a diagram of an embodiment in which the pay out mean is not
immersed in the fluid;
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9
Figure 13 shows apparatus including sealed container means;
Figure 14 shows apparatus including a sealed container and a capillary;
Figure 15 shows apparatus including a sealed container and a pay out means;
Figures 16 and 17 show application in oil wells; and
Figure 18 shows application in oil refineries.
With reference to Figure 1, there is provided apparatus for the remote
measurement of physical parameters, which apparatus comprises sensing means 1
for
sensing one or more physical parameters, interrogation means 2 for
interrogating the
sensing means 1 and making a measurement, a cable 3 for extending between the
sensing
means 1 and the interrogation means 2, a conduit 4 for extending to a
measurement
location 5 and which is of such a cross-sectional size that it is able to
accept the cable 3
and the sensing means 1, and cable installation means 6 for installing the
sensing means
1 and the cable 3 through the conduit 4 and for placing the sensing means 1 at
the
measurement location 5, the cable installation means 6 being such that it
includes means
7 far propelling a fluid along the conduit 4, and the conduit 4 being such
that it contains
a lead-in section 8 for providing sufficient fluid drag on the cable 3 as it
enters the
conduit 4 from the cable installation means 6 to ensure that the sensing means
1 is able to
be transported through the conduit 4. The cable 3 is shown wound on a drum 9
is Figure
1.
The sensing means 1 may be any sensor of a size and disposition that it can be
pumped through the conduit 4. The sensing means 1 may be one or more optical
fibre
sensors. These optical fibre sensors may include sensors for measuring
temperature,
distributed temperature, pressure, acoustic energy, electric current, magnetic
field,
electric field, or a combination thereof.
The interrogation means 2 may be instrumentation electronics.
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lU
The interrogation means 2 may be an electro-optic electronic readout system
suitable for interrogating the appropriate optical fibre sensors and may
include one ar
more optical fibre amplifiers.
The cable 3 may be one or more optical fibre cables. These may be
hermetically sear with carbon coating, may have high-temperature coatings such
as
polyimide, or silicone or polytetrafluoroethelene, or may have combinations of
these
coatings.
The means 7 for propelling a fluid may be a hydraulic pump, a gas bottle, a
gas
compressor, a gas compressor linked to a contai~xr of liquid, or a combination
thereof.
The fluid may be a gas such as nitrogen or methane.
The fluid may ahernatively be a liquid such as water, a mixture of water and
glycol (which is preferable for applications in areas where sub-zero
temperatures occur
fi~equently), a low-viscosity hydrocarbon oil, or a low-viscosity silicon or
polysiloxat~e
od, or a perfluorocarbon fluid. Silicone or polysiloxane oils or
perfluorocarbon fluids
may be preferable for high-temperature applications where it is preferable to
prevent
water coming into contact with the cable 3. Following deployment using a
fluid, the
fluid may be replaced by one or more different fluids which may be preferable
for the
long-term preservation of the sensing means 1 aad the cable 3. For example, it
may be
convenient to use demineralised water for the deployment of the cable 3. The
water
can be pumped out with an alcohol (such as isopropylalcohol) in order to dry
the
conduit 4 out, and then the alcohol displaced with dry nitrogen or a silicone
oil.
The cornluit 4 may be high-pressure tubing with an inside diameter and
pressure rating to make it suitable for deploying sensors to remote locations.
The conduit 4 may be steel hydraulic control line comrranly used in the oil
and
gas industry having an external diameter of 1I8" to'/," (3mm to l9mm).
Alternatively,
CA 02471867 2004-07-14
the conduit 4 may be coiled tubing commonly used in the oil and gas industry
having
an external diameter of'/," to 2" ( l9mm to SOmm).
The lead-in section 8 should be long enough and straight enough so that fluid
flow is sufficient to cause the cable 3 and sensing means 1 to be propelled
into and
continue to be propelled into the conduit 4 while the fluid is flowing without
causing
the cable 3 to stall in the lead-in section 8.
The lead-in section 8 shall preferably have approximately the same internal
diameter as the conduit 4 and there shall preferably be a smooth transition at
the
intersection between the lead-in section and the conduit 4.
Tlx lead-in section 8 preferably does not contain sut~tantial bends having
bend
radii less than 100 times the internal cross-sectional radius of tl~ lead-in
section 8.
Such bends can lead to excessive frictional forces being applied to the cable
3 while the
fluid is flowing leading to failure of the deployment of tlx sensing means 1.
The lead-in section 8 preferably does not contain bends which cause the cable
3
when tensioned in the lead-in section 8 to engage multiple surfaces of the
lead-in
section 8 and in which at least two of these surfaces are separated by a
distance less
than 10 times the internal cross-sectional diameter of the lead-in section 8.
The lead-in section 8 is preferably a substantially straight section of tubing
which is at least 2 meters long. The tubing may be a straight section of the
conduit 4.
The lead-in section 8 is preferably of such a design that if the conduit 4 is
detached from the lead-in section 8, and the transport of the cable 3 through
the lead-in
section 8 commenced using the cable installation means 6, then the cable 3
will
continue to be transported through the lead-in section 8 if a tensile load of
up to 1
CA 02471867 2004-07-14
lz
Newton is applied to the cable 3 at the exit of the lead-in section 8 for more
than one
minute, and where the cable 3 will start to transport again if the motion of
the cable 3
is stalled at the exit of the lead-in section 8 for more than two seconds.
This represents
a good test as to whether the design of the lead-in section 8 will provide
reliable
deployments of sensors and cables. A further qualification is to attach a 1 m
to Sm
length of tubing of similar cross-sectional design to the conduit 4 to the
lead-in section
8 where the tubing is coiled with a diameter of around 1 Ocm and to repeat the
pulling
and the stalling tests. Additional qualification would be to replicate the
path which the
co~uit 4 would take over a length which contains the majority of the initial
bends and
curves in the actual installation and to repeat the pulling and the stalling
tests. This
would be particularly advantageous prior to installing a sensing means 1
through a
conduit 4 in an oil well because there are often sharp bends and loops within
the well
head.
It is convenient to use hydraulic control line in the lead-in section 8. It is
often
difficult to straighten hydraulic control line perfectly if it has been
previously stored in
a coiled form. The installation of the cable 3 and sensing means 1 will be
reliable
provided that hydraulic control line is not too distorted. For example,
deployments of
polyimide-coated fibre cables joined to optical fibre sensors can be achieved
reliably
through'/." (6mm) hydraulic control line when bends and kinks have been
reduced
such that the optical fibre cables would not have pressed against the side
walls of the
hydraulic control line along a 100mm length of the hydraulic control line when
the
optical fibre cable is held straight. The fluid is preferably water and the
fluid flow rate
is preferably around 0.5 to 2 litres per minute.
CA 02471867 2004-07-14
13
The interrogation means 2 need not be connected to the sensing means 1 while
the sensing means 1 is pumped through the conduit 4 to the measurement
location 5.
In many instances it is preferable to remove the cable installation means 6
and the lead-
in section 8 oixe the sensing means 1 is located at the measurement location
S, form a
seal around the cable 3 where it enters or exits from the conduit 4, and then
connect
the cable 3 to the interrogation means 2 with a separate cable specially
designed for
surface cabling.
In some instances, it may be preferable to pump the sensing means 1 and the
cable 3 through the conduit 4, and then to place the conduit 4 such that the
sensing
means 1 is located at the measurement location 5. An example is where the
sensing
means 1 and cable 3 is pumped into the conduit 4 (which may be hydraulic
control line
or coiled tubing) which is then subsequently lowered into an oil well in order
to take a
measurement. The conduit 4 can then be removed from the oil well and lowered
into
one or more oil wells to repeat the measurement. It will be appreciated that
it may be
preferable to weight the conduit 4 prior to lowering it into the oil well. The
conduit 4
when inserted into the oil well may be configured as a single charnel from the
surface
into the oil well, or may be configured such that it extends into the oil well
and then
returns back to the surface again.
Figure 2 shows an embodiment, in which the cable installation
means 6 includes a lead element 21 attached to the sensing 1 by a second cable
22 which ensures that the lead element 21 is always able to contribute a net
propelling
force to avoid the sensing means 1 from stalling or to overcome a temporary
stalling of
the sensing means 1 while the fluid is flowing along the conduit 4. This is
particularly
advantageous when the sensing element 1 is relatively stilt and causes
significant
friction as it circumvents bends in the conduit 4. The lead element 21 can
either be
attached to the sensing means 1 by the second cable 22, or be attached
directly to the
sensing means 1 as shown in Figure 3.
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14
The lead element 21 may be a pig, a piston, a drone or a parachute. The lead
element 21 is preferably designed to prevent it from stalling against the side
wall of the
conduit 4 where the conduit 4 is bent. Such a design helps prevent a common
failure in
deploying sensors through hydraulic control lines containing bends and loops.
Where
bends and loops are encountered, there is a tendency for the leading section
of the
sensing means 1 or cable 3 to stop temporarily while the cable 3 following is
still
deploying. The consequence is that the cable 3 spirals around the side wall of
the
conduit 4, a situation which can be non-recoverable. Designs of the lead
element 21
which keep the leading section og the side walls of the conduit 4 help prevent
this
failure mechanism. A more preferable solution is to design the conduit 4 to
avoid
sharp bends wherever possible, but this may not always be possible in well
heads for
use in the oil industry.
The lead element 21 may also be a long length of flexible optical fibre.
Figure 4 shows an embodiment, where the apparatus includes a
first port 41 where the fluid enters into the lead-in section 8, and a first
orifice means
42 through which the cable 3 may be progressively pulled while deploying the
sensing
means 1, where the first orifice means 42 is such that suffcient fluid flows
through the
conduit 4 in order to transport the sensing means 1 to the measurement
location 5.
In order for the cable 3 to be pulled through the orifice means 42, it is
necessary to overcome opposing forces including the repelling force from the
pressure
differential from inside the lead-in section 8 to the ambient pressure, any
frictional
forces of the cable 3 against the first orifice means 42 or any fluid drag due
to fluid
exiting through the orifice means 42. These opposing forces are not excessive
for thin
fibre optic cables such as polyimide-coated optical fibre having an outer
diameter of
approximately 1 SOum. Nevertheless, the length of the lead-in section 8
typically needs
to be greater than around S meters and needs to be fi~ee of rapid undulations.
Such
rapid undulations can cause the optical fibre to press against the wall of the
lead-in
CA 02471867 2004-07-14
IS
section 8 inducing friction and also reducing the fluid drag on the optical
fibre. This
embodiment is suitable for deploying sensors through lengths of hydraulic
control line
in excess of I OOm. It should be noted that if applications require a longer
length of the
hydraulic control line, then the applied pressure needs to be increased to
maintain the
fluid flow rate through the conduit 4. Consequently the repelling forces
increase, and
it is preferable to increase the length of the lead-in section 8 to
compensate.
The first orifice means 42 may comprise a deformable insert 51 as shown in
Figure 5 which can be deforrr~ed in order to provide a close fit around the
cable 3 as it
is being pulled through the deformable insert 51. The defonmable insert 51 is
typically
deformed by squeezing it between first metal plate 52 and second metal plate
53
connected by a screw thread 54. Such an arrangement is commonly referred to as
a
stuffing box, and is common in the oil industry in slickline operations.
The first orifice means 42 may comprise a wireline injector suitably modified
for small diameter cables such as coated optical fibres.
The first orifice means 42 may include a capillary 61, as shown in Figure 6,
which is connected to the conduit 4 through which the cable 3 may be
progressively
pulled while deploying the sensing means 1. The capillary 61 may preferably be
designed to form a close fit around the cable 3 to prevent excessive fluid
escaping ..
through the capillary 61 while the sensing means 1 is being deployed. The
entry into
the capillary 61 may preferably be shaped so as not to damage the cable 3.
Such an
embodiment relaxes the length requirement on the lead-in section 8. The
straight
section needs to be greater than around 4 meters for deploying typical optical
fibre
cables through'/," (6mm) hydraulic control line with flow rates of around 0.5
to 2
litres per minute.
Figure 6 also shows a diameter restriction 62 in the lead-in section 8 in
order to
reduce the pressure of the fluid at the end of the capillary 61 where the
cable 3 enters
into the lead-in section 8. The advantage is to reduce the backward force on
the cable
CA 02471867 2004-07-14
16
3, to increase the forward drag on the cable 3 at the exit 63 of the capillary
61, and to
reduce fluid loss through the capillary 61. The diameter restriction 62 is
preferably
designed with an adiabatically reducing taper followed by an adiabatically
increasing
taper in order to minimise the overall pressure loss in the lead-in section 8
as measured
after and before the diameter restriction 62.
Figure 7 shows an embodiment, where the apparatus includes
an exit port 71 at the end of the lead-in section 8 in order to increase the
rate that fluid
flows in the lead-in section 8 and thus increase the fluid drag on the cable
3. This has
the advantage of relaxing the length requirement on the lead-in section 8.
The exit port 71 may include a valve ?2 which is preferably closed once the
sensing means 1 has been positioned at the measurement location.
The exit port 71 may include a viscojet (not shown) designed to ensure that
the
fluid flowing through the exit port 71 does not create excessive turbulence in
the
conduit 4.
Figure 8 shows an embodiment, where the apparatus includes a
first port 41 where the fluid enters into the lead-in section 8 and a first
and second
orifice means 81 and 82 through which the cable 3 may be progressively pulled
while
deploying the sensing means 1, where the design of the first and second
orifice mesas
81 and 82 is such that sufficient fluid flows through the conduit 4 in order
to h~ansport
the sensing means 1 to the measurement location 5. A second port 83 is shown
between the first and second orifice means 81 and 82 for reducing the fluid
flowing
from the lead-in section 8 through the second orifice means 82 while the
sensing means
1 is transported to the measurement location 5. The fluid flowing through the
second
port 83 may be controlled using a valve 84 or a choke.
The second port 83 may be connected to the means 7 for propelling the fluid
along the conduit 4 as shown in Figure 9. Such an arrangement is useful in oil
well
applications for reducing the risk of gases such as light hydrocarbons or
hydrogen
CA 02471867 2004-07-14
17
sulphide or other poisonous gases escaping from the conduit 4 through the
second
orifice means 82.
The apparatus may include a plurality of orifice means 82 and in which each
orifice means 82 contains at least one port 83 for progressively reducing the
fluid
flowing through each orifice means 82 from the lead-in section 8. The fluid
flowing
through each port 83 may be regulated using a plurality of valves 84.
The design of the lead-in section 8 should be similar to that descn'bed for
Figure 6.
Figure 10 shows an embodiment, where the apparatus includes
a first port 41 where the fluid enters into the lead-in section 8, a first
orifice means 42
through which the cable 3 may be progressively pulled while deploying the
sensing
means 1, and where the cable instal)ation means includes a pay out means 101
for
contmlling the rate at which the cable 3 deploys. The pay out means 101
comprises a
powered wheel 102 and a wheel 103 which grip the cable 3 and pull it through
the
orifice pans 42. The pay out means 101 is preferably controlled to limit the
rate at
which the cable 3 is deployed, and to make the rate at which the cable 3 is
deployed
independent of the fluid flow rate.
This embodiment has the advantage that the wheels 102, 103 overcome the ~~
opposing forces in the orifice means 42. It is therefore possible to relax the
length
requirement on the lead-in section 8. The lead-in section 8 should preferably
be
straight and should preferably be longer than 3m.
Moreover, it is possible to deploy sensors through longer lengths of hydraulic
control line than is possible in the embodiments described in Figures 2 to 9.
We have
demonstrated deploying sensors through 10,OOOpsi (69MPa) rated %," (6mm)
hydraulic
control line with a pressure drop per unit length as low as 0.3psi/m (2kPa/m).
This
extrapolates to a deployment distance through the conduit 4 of 30km being
achievable
with this embodiment.
CA 02471867 2004-07-14
18
Figure 11 shows a preferred embodiment of the pay out means 101 which
comprises a wheel 111 powered by a motor (not shown) around which the cable 3
is
wrapped. The advantage of this approach is that the cable 3 will only be
pulled
through the first orifice means 42 if the cable 3 is tensioned by the fluid
flowing in the
conduit 4. Thus if the demand for cable 3 to be deployed stops temporarily the
friction
of the cable 3 on the wheel 111 will reduce significantly and the cable 3 will
stop being
pulled through the orifice means 42. It should be noted here that deployment
will only
start again if the lead-in section 8 is sufficiently straight and long that
suflxcient tension
cau be induced in the cable within the lead-in section 8 by fluid drag such
that the cable
3 will grip the wheel 111 again. If it is found that the lead-in section 8 is
not
sufficiently long and the deployment has stalled, then it is often possible to
restart
deployment by pulsing the pressure of the fluid in the conduit 4, or by
preventing
fiuther deployment of the cable 3 over the wheel 111 and increasing or pulsing
the
flow of fluid through the conduit 4.
By way of example, the fluid may be water and the first orifice means 42 may
be a steel capillary, 20mm long and may have an internal diameter of around
O.Smm to
lmm, an arrangement which prevents excessive loss of $uid through the
capillary and
allows deployment over many kilometres of'/," hydraulic steel tubing and 800um
outer
diameter optical fibre. This implementation is attractive for deploying an
optical fibre
such as used for measuring temperature profiles with a distn'buted temperature
sensor
such as the York DTS 80 manufactured by York Sensors Ltd in England. Such an
installation may be conducted by having the optical fibre wound in a container
such as
a spool or bobbin, winding it around the wheel 111, feeding a two metre length
of fibre
into the hydraulic steel tubing through the capillary, turning on a water pump
to drive
water through the conduit 4 via the first port 41 (far example a T-piece), and
driving
the wheel 111 to pull fibre offthe bobbin as the fibre is deployed through the
hydraulic
tubing. The cable installation means 6 may be removed taking care not to
damage the
optical fibre, and the optical fibre can be interfaced to the interrogation
means 2 which
CA 02471867 2004-07-14
19
in this instance is the York DTS80. It may be convenient to seal the hydraulic
tubing
around the optical fibre in order to prevent fluid loss. In practice it is
preferable to
keep the first metre or two of the hydraulic tubing following first port 41 as
straight as
possible.
The pay out means 101 may alternatively be located the other side of the first
orifice means 42 as shown in Figure 12. Here the pay out means 101 comprises a
drum 121 whose speed may be controlled by a motor (not shown). The rate of
deployment can also be limited by a brake mechanism, a friction mechanism, or
may be
simply controlled by the operator placing his hand on the drum 121 to prevent
the
cable 3 and sensing means 1 deploying too quickly.
Figure 13 shows an embodiment, where the cable installation
means 6 includes a first port 41 where the fluid enters into the conduit 4,
and a sealed
container 131 for holding the sensing means 1 and the cable 3 prior to pumping
the
sensing means 1 to the measurement location 5. The cable 3 is held on a cable
holder
132 prior to deployment except for a short length of cable 3 which is
introduced into
the lead-in section 8 prior to pumping the fluid. This embodiment is preferred
for
deploying sensors into high-pressure oil or gas wells, or subsea oil and gas
wells.
The cable holder 132 may be a rotating cable drum holder which rotates as the
cable 3 is pulled off it. The end of the cable 3 which is not being deployed
through the
conduit 4 may be connected to interrogation means 2 (not shown) through a high-
pressure, fibre-optic rotary joint such as a Model 145 manufactured by Focal
Technologies of Nova Scotia, Canada. This may be advantageous if it is desired
to
monitor the deployment of the sensing means 1 and the cable 3 by, for example,
time
domain reflectometry.
Optical time domain reflectometry can be used to monitor the deployment of
optical fibre cable because of the increased attenuation of the optical fibre
cable on the
rotating cable drum. The lower attenuation of the optical fibre cable which
has bin
CA 02471867 2004-07-14
dispensed off the cable holder 132 can be very noticeable, particularly for
multimode
optical fibre or monomode optical fibre operating in a regime where bend
losses are
noticeable. (These bend losses would also be noticeable in the embodiment
shown in
Figure 11 where the fibre cable is wrapped around the wheel 111.)
The cable holder 132 may be connected to a brake mechanism (not shown) in
order to restrain the cable 3 as it is transported through the corxiuit 4. The
brake
mechanism may comprise magnets acting on a copper disk to induce eddy currents
and
thereby provide resistance to the cable 3 as it is being deployed.
The brake mechanism may be driven by an external motor (not shown) coupled
to the cable holder 132 via a high-pressure bearing or via a magnetic clutch.
It is
preferable that the motor is configured to provide constant torque (and not
constant
velocity) on the cable 3 as it is being deployed.
The cable holder 132 may alternatively be a cassette where the cable 3 is
wound either on the inside of the cassette or the outside of the cassette and
the cable 3
is pulled off without rotating the cassette. Examples of such cassettes are
found in
wire guided missiles and torpedoes where it is important that communication
thmugh
tl~ wire is maintained after launching.
The cable installation means 6 may include a short length of capillary 141 as
shown in Figure 14 to provide better entrainn~ent of the cable 3 as it enters
the lead-in
section 8. The capillary 141 is attached to the conduit 4 by means 142.
The cable installation means 6 may also include a pay out means 151 as shown
in Figure 15 comprising a wheel assembly 152 housed in a pay out container
153. The
purpose of the pay out means 151 is to control the rate at which the cable 3
enters into
the lead-in section 8 independent of the fluid flow rate. The wheel assembly
152 may
comprise a wheel around which the cable is wrapped. The wheel may be driven by
an
external motor which drives the wheel either through a high-pressure bearing
or via a
mag«etic clutch. The friction between the wheel and the cable 3 provides the
force to
CA 02471867 2004-07-14
21
pull the cable 3 offthe cable holder 132. This friction will only be large
enough to pull
the cable 3 off the cable holder 132 if suff cient drag is being induced by
the fluid on
the cable 3 - particularly in the lead-in section 8 during the early stages of
deployment.
It is found that a straight lead-in section 8 of around 2m is suffcient to
ensure reliable
deployment.
It will be appreciated that it is not always possible to provide enough space
for
a straight lead-in section 8. An alternative in these cases is to reduce the
straight
section to around O.Sm in total, and to lead it very gently into a large loop
containing
several meters of conduit 4. If the conduit 4 is '/." (6mm) hydraulic control
line, then
the minimum bend radius should be no less than around O.Sm - although a lm
bend
radius would be preferable. Normal plumbing practice would be to form right
angle
bends of around 1" (25mm) bend radius to provide a compact installation unit.
Such
right angle bends placed near to the first port 41 will lead to unreliable
deployment of
the cable 3 and can prevent the cable 3 from deploying. It should be noted
that
undulations in the hydraulic control line should be straightened as much as
possible.
Figure 16 shows an example of how the embodiment shown in Figure 4 may be
used for deploying sensors into an oil well 1630, comprising a casing 1631, a
well head
1632, a length of production tubing 1633 through which oil flows from a
reservoir (not
shown) to the surface, and a packer 1634 for isolating the pressure from the
reservoir
from the surface. A hydraulic control line 1635 is strapped to the production
tubing
1633 using straps 1636. The hydraulic control line 1635 passes down the oil
well
1630, turns around at the U-bend 1637, and passes back up the oil well again.
The
hydraulic control line 1635 exits the well head 1632 via ports 1638. It is
usual to find
that the hydraulic control line 1635 is wrapped several times around the
production
tubing 1633 within the well head 1632, although these wraps are not shown in
Figure
16.
CA 02471867 2004-07-14
22
Figure 16 also shows the hydraulic control line 1635 wrapped around the
production tubing 1633 several times which may be advantageous for some
sensing
applications, for example for increasing the resolution of thermal profiling.
This may
be particularly important when the oil well 1630 contains an electrically
submersible
pump which is driven by a motor. It would be advantageous to wrap the
hydraulic
control line 1635 around both the pump and the motor in order to increase the
effective spatial resolution of a thermal profiling sensor which may be
installed into the
hydraulic control line 1635 using the apparatus described.
The deployment apparatus 1610 for installing sensors through the hydraulic
control line 1635 can be one of the preceding embodiments which must be
selected for
its applicability. All of these embodiments require the lead-in section 8
which is shown
separately in Figure 16. For example, if the oil well 1630 is a low-pressure
oil well,
and the hydraulic control line 1635 is'/," (6mm) steel hydraulic control line
and is not
too long (for example 100m) then the embodiment shown in Figure 4 can be used,
with
a lead-in section 8 of around Sm in length - the precise figure depending on
the
stiffness and diameter of the cable 3. However, if the length of hydraulic
control line
1635 is significantly longer (for example 3km), then the embodiments shown in
Figure
to 15 are preferred. Depending on the exact embodiment, the length of the lead-
in
section 8 can then be reduced to around 2m.
It will be appreciated that if a sensor is to measure the pressure within the
production tubing 1633, then it is necessary to communicate pressure from the
production tubing 1633 to the hydraulic control line 1635. This can be
achieved with a
small orifice which would preferably contain .a device to restrict the flow
from the
hydraulic control line 1635 to the production tubing 1633 while the sensor is
being
installed. Alternatively, the pressure communication can be achieved with a
wireline-
deployable valve such as is known in the oil and gas industry.
CA 02471867 2004-07-14
23
In use, the hydraulic control line 1635 would be installed into the oil well
1630
as the production tubing 1633 is being lowered into the ground. The
installation of the
oil well 1630 would then be completed and the sensors installed into the
hydraulic
control line 1635 at a convenient time later. This is achieved, by connecting
the
deployment apparatus 1610 to the oil well 1630 with external hydraulic control
line
1640, and pumping the sensor through the hydraulic control line 1635 and the
external
hydraulic control line 1640 using fluid. The fluid can be collected at the far
end 1641
by a vessel (not shown) which may be designed so that the entire deploy~nt
apparatus 1610, hydraulic control line 1635 and the external hydraulic control
line
1640 is a sealed system If a sensor were to fail during or subsequent to its
installation,
it can be pumped out of the hydraulic control line 1635, the hydraulic control
line 1635
cleaned (for example by pumping through solvents, a plug of wire wool or a
combination of both) and a replacement sensor installed using the deployment
apparatus 1610.
Following the installation of the sensor, the external hydraulic conduit 1640
is
removed taking care not to sever the fibre optic cable, and the fibre-optic
cable
connected to the interrogation means 2 with a separate cable designed for
external
cabling. Alternatively, it may be conven~nt to form the connection to the
interrogation
means 2 using fibre optic cable which is pumped through hydraulic control line
using
the deployment apparatus 1610.
In many installations, the hydraulic control line 1635 may experience high
pressures subsequent to the installation of the sensing means 1. In these
cases, it is
preferable to include a splice chamber (not shown) at or near the well head
such that
the cable 3 may be spliced to a high-pressure fibre optic seal which in turn
is connected
to the interrogation means 2 via a separate cable. In order to gain access to
the cable 3
for fusion splicing, it is preferable that the splice chamber is of such a
diameter that it
can contain several esters of fibre-optic cable. Fire-proofing safety
requirements can
CA 02471867 2004-07-14
24
be satisfied by separately protecting the splice chamber with an external
casing. It will
be appreciated that in order to gain access to the cable 3 for fusion
splicing, it is
necessary to isolate the well pressure. This can be achieved either by pumping
a
higher-density fluid into the hydraulic control line 1635 through a port
(which can be
provided in the splice chamber), or by forming an annular seal around the
fibre inside
the conduit 4 by using, for example, a valve which contains an elastic
deformable
element.
Figure 17 shows an example of how the deployment apparatus 1710 shown in
Figure 15 may be used for deploying sensors into an oil well 1730. The lead-in
section
8 is shown separately. The embodiment is particularly useful where for high-
pressure
wells, subsea wells, or wells where the length of the hydraulic conduit 1635
is very
long (greater than 1 km). Figure 17 shows the channel foamed by the hydraulic
conduit
1635 penetrating the packer 1634 such that a sensing means 1 (not shown) can
make
measurements near the perforations 1733 where oil flows from the reservoir
into the
productian tubing 1633. This is achieved using a packer penetrator 1734.
The far end 1641 of the hydraulic conduit 1640 is shown routed back to the
deployment apparatus 1710 in order to form a closed system The deployment
apparatus 1710 can be located on or conveniently near the well head 1731, on a
platform or on the sea bed.
The designs and procedures for installing the hydraulic conduit 1635, the
clamps 1636, and the packer penetrators 1734 are known in the oil industry and
are
used frequently for installing control lines either for chemical injection or
for the
hydraulic actuation of downhole valves or mechanical actuation devices used in
so-
called "smart wells" which are currently being developed by several oil-field
service
companies. Technology also exists for drilling spurs into the formation around
the oil
well 1730 into which coiled tubing can be inserted. Such coiled tubing can
contain the
conduit 4 so that a sensing means 1 can be placed to make measurements (such
as
CA 02471867 2004-07-14
acoustic, seismic, temperature or pressure) within the formation, reducing
influence of
the fluid flow in the production tubing 1633.
It should be noted that whereas the packer penetrator 1734 is shown
penetrating the packer 1634 directly, a channel through the packer 1634 could
equally
bypass the packer 1634 via a sleeve which could be inserted near the packer
1634
using wireline techniques. An alternative approach would be to pump the
sensing
means 1 through channels in the casing 1631.
The well shown has a well head 1731 similar to that used in subsea completions
containing stab connectors 1732 which are mated when the well head is lowered
into
place. Figure 17 also shows a packer penetrator 1734 which allows the channel
formed by the hydraulic conduit 1635 to pass through the packer 1634.
The deployment apparatus 1710 would also be useful for deploying sensors
into high-pressure wells, or in wells where the length of the hydraulic
control line 1633
is very long (SOOm to 3km, or up to 30km as oil-well drilling technologies
improve)
Figure 18 shows how a deployment apparatus 181 can be used to pump a
sensing means 1 (not shown) for stack monitoring in a stack 182, for process
monitoring in process plant 183, or for monitoring reactions in catalytic
converters
184. Hydraulic control lines 185 are routed up the stack 182 to a measurement -
location 186 where an interface (not shown) to enable the sensing means 1 to
measure
outputs from the stack 182 is required. The interface may be a thermal path
for the
measurement of temperature, or may include a window to enable optical or infra-
red
gas sensors to monitor stack emissions, or may include a sampling cl~nber to
enable
gas sensors (including non-optical) to monitor stack emissions. Figure 18 also
shows
the hydraulic control line 185 being routed through process vessels 188 where
it forms
loops 187 in order to increase the number of points that can be sampled by the
sensing
means 1 pumped through the hydraulic control line 185. The monitoring of
catalytic
converters 189 by forming loops 187 also increases the number of points that
can be
CA 02471867 2004-07-14
26
sampled by the sensing means 1. Connectors 1810 allow the operator to select
the
hydraulic control line 185 through which the sensing means 1 is to be
deployed. The
hydraulic control line 185 can be manufactured from steel, titanium, or
materials which
are chemically inert and can withstand high pressures.
It is to be appreciated that the embodiments of the invention described above
with reference to the accompanying drawings have been given by way of example
only
and that modifications and additional components may be provided to enhance
the
performance of the apparatus.
