A WELLBORE SURVEILLANCE SYSTEM
Field of the invention
The present invention relates to a wellbore surveillance system for obtaining fluid
reservoir information data, such as the position and quantity of gas, oil and/or
water, while draining hydrocarbons from an oil or gas field via a casing in a wellbore
in a formation, the casing having a vertical part near a top of the casing and
an inner face, the system comprising a first sensor for measuring a content of
gas, oil and/or water in the formation, and a second sensor for measuring a con
tent of gas, oil and/or water in the formation.
Background art
Conventional reflection seismology uses surface sources and receivers to detect
reflections from subsurface impedance contrasts in order to obtain data of fluid
reservoir information. The obtained image often suffers in spatial accuracy, reso
lution and coherence due to the long travel paths between source, reflector, and
receiver. To overcome this difficulty, a technique commonly known as vertical
seismic profiling was developed to image the subsurface in the vicinity of a bore
hole. By this method, a surface seismic source is placed in the drilling tool, and
signals are received by a single downhole receiver or an array of downhole re
ceivers within the same drilling tool. This step is repeated for different depths of
the receiver (or receiver array). This method is used for drilling but is also suit
able for obtaining fluid reservoir information data in the subsequent production
optimising process.
Another known method is to arrange an array of seismic sensors distributed
along jointed tubulars (e.g. drill pipe or coiled tubing) to determine the physical
condition of the drill string and whether drilling may be optimised. The seismic
sensors are configured to detect seismic energy imparted into the adjacent formation
by a wellbore source or surface source. This method is used for drilling
but is also suitable for obtaining fluid reservoir information data in the subse
quent production optimising process.
In addition, an optical fibre can be arranged in the well in order to obtain tem
perature data of the fluid in the vicinity of the well but not fluid reservoir informa
tion data, such as the position and quantity.
Description of the invention
It is an object of the present invention to wholly or partly overcome the above
disadvantages and drawbacks of the prior art. More specifically, it is an object to
provide a method and a system for obtaining fluid reservoir information data,
such as the position and the amount of gas, oil and water, while draining hydro
carbons form an oil or gas field.
The above objects, together with numerous other objects, advantages, and fea
tures, which will become evident from the below description, are accomplished by
a solution in accordance with the present invention by a wellbore surveillance
system for obtaining fluid reservoir information data, such as the position and
amount of gas, oil and/or water, while draining hydrocarbons from an oil or gas
field via a casing in a wellbore in a formation, the casing having a vertical part
near a top of the casing and an inner face, the system comprising :
- a first sensor for measuring a content of gas, oil and/or water in the formation,
and
- a second sensor for measuring a content of gas, oil and/or water in the forma
tion,
wherein the first and the second sensors are arranged at least partly in a casing
wall of the casing, and the second sensor is arranged at a distance from the first
sensor.
Having two sensors at a distance from one another makes it possible for one sen
sor to send out a signal in the formation and for the other sensor to detect the
response from that signal. In this way, fluid reservoir information data can be ob
tained.
The wellbore surveillance system according to the invention may further comprise
a second casing arranged in a second wellbore and comprising a first sensor for
measuring a content of gas, oil and/or water in the formation, and a second sen
sor for measuring a content of gas, oil and/or water in the formation, wherein the
first and the second sensors are arranged at least partly in a casing wall of the
second casing, and the second sensor is arranged at a distance from the first
sensor.
In one embodiment of the invention, the casing may have a second part more
horizontal than the first part, and the sensors may be arranged in this second
part.
By arranging the sensors in the second, more horizontal part, fluid reservoir in
formation data can be obtained from a larger distance than with known measuring
tools lowered into a well.
Furthermore, the system may have more than five sensors, preferably more than
ten sensors, and more preferably more than twenty sensors.
In one embodiment, the first sensor may comprise at least one transmitter of a
first signal, at least one receiver receiving the first signal and/or a second signal,
and at least one transferring device, and the second sensor may comprise at
least one transmitter of the second signal, at least one receiver of the first signal
and/or the second signal, and at least one transferring device.
When each sensor has a transmitter and a receiver, the system may still function
if one transmitter or receiver in a sensor breaks down.
In another embodiment, the sensors may be arranged in an opening in the inner
face of the wall of the casing or a through-hole in the wall of the casing.
Moreover, the sensors may be arranged in the wall of the casing, forming part of
an outer face of the casing and in contiguity with the well fluid and/or the forma
tion.
Also, the sensors may extend from the inner face of the casing and into the for
mation surrounding the casing.
Further, the transmitter may be an acoustic transmitter.
In one embodiment, the acoustic transmitter may comprise a hammer or a
weight.
Additionally, the acoustic transmitter may comprise a motor for pulling the
weight in one direction and releasing the weight which, by means of a spring
means, is forced in a second direction opposite the first direction towards the
formation to abut the formation.
Furthermore, the receiver may comprise an acoustic receiver.
In one embodiment, the acoustic receiver may be an accelerometer.
In another embodiment, the receiver may comprise a motor for pulling the
acoustic receiver in one direction and subsequently forcing the acoustic receiver,
by means of a spring means, in a second direction opposite the first direction t o
wards the formation to abut the formation.
In addition, the motor may pull the weight or the acoustic receiver in one direc
tion by means of a rotating shaft.
Also, the acoustic receiver may be a microphone.
Furthermore, the first sensor may comprise a first and a second electrode for
providing a current flowing from the first electrode to the second electrode to
conduct a resistivity measurement or a conductivity measurement of the forma
tion in order to determine the content of gas, oil and/or water in the formation.
Moreover, the sensor may comprise a microchip for transforming the signal or
the resistivity or conductivity measurement into data and/or for storing and/or
transferring the data, or for storing a representation of the data.
The present invention as described above may further comprise at least one tool
comprising a communication device for receiving data from the transferring de
vices when the tool is in the casing.
Also, the present invention may comprise at least one tool comprising an acoustic
transmitter having a weight connected with a rotatable shaft rotated by a motor
in the tool.
Further, the tool may comprise an anchor section for anchoring the tool within
the casing.
In one embodiment, the anchor section may comprise at least a first anchor extending
in a first radial direction of the tool and a second anchor extending in a
second direction opposite the first direction, the extension of the anchors from an
outer face of a tool housing varying so that the tool is anchored in an eccentric
relationship to the casing.
Furthermore, the tool may comprise a driving unit, such as a downhole tractor.
In one embodiment, the tool may comprise means for making a cavity in the cas
ing. The means for making a cavity may be a drilling unit.
Moreover, the tool may comprise means for arranging a sensor in the cavity.
In one embodiment, the means for arranging the sensor in the cavity may be a
rotating arm for rotating the sensor so that a thread of the sensor engages a
thread in the cavity.
In addition, the transferring device and the communication device in the tool may
use radio frequency for transferring data to the tool.
Moreover, the transmitter and the receiver of the sensor may be integrated as
one unit.
Additionally, the transferring device may comprise a radio frequency identification
tag, and the communication device may comprise a radio frequency identification
reader.
In an embodiment of the invention, the sensor may comprise a battery for pow
ering at least the transmitter and the receiver.
Furthermore, the tool may be connected with a wireline for powering the tool and
for transmitting data to above the wellbore.
In addition, the tool may comprise a battery for powering the tool.
Moreover, the tool or the communication device may comprise a powering device
for powering the sensor.
In another embodiment, the powering device and the sensor may comprise an
inductive coupling for transferring power from the tool to the sensor through in
duction.
Furthermore, the inductive coupling may be used for transferring data from the
sensor to the tool.
Additionally, the sensor may comprise a processor for transforming the signal or
the resistivity or conductivity measurement into data and/or for storing and/or
transferring the data, or for storing a representation of the data.
In an embodiment, these signals may be generated by acoustics.
In yet another embodiment, the transferring unit in one sensor may have a wire
less communication means for communicating wirelessly with another wireless
communication means in another sensor or with a wireless communication means
in a communication device arranged closer to the top of the casing.
Moreover, the system may comprise several communication devices arranged at
a predetermined mutual distance along the casing to the top of the casing, the
distance being determined by the distance over which two devices are capable of
communicating wirelessly with each other.
In addition, the system may comprise several sensors with wireless communica
tion means arranged at a predetermined mutual distance along the casing to the
top of the casing, the distance being determined by the distance over which two
devices are capable of communicating wirelessly with each other.
Also, the system may comprise a hammering device arranged at surface or sea
bed for transmitting acoustic waves into the formation.
Additionally, the signal may be a low frequency acoustic or sonic signal at a f re
quency of 1 Hz-100 kHz, preferably 10-50 kHz, and more preferably 15-35 kHz.
Furthermore, the invention relates to a downhole tool for reading the data of the
sensors in the downhole system as described above, wherein the tool may com
prise driving means, such as wheels, for driving the tool forward in the casing,
and a communication device as described above.
The present invention further relates to a method for installing the system as de
scribed above, comprising the steps of:
- providing a number of cavities at a distance from one another in the casing in
the wellbore, and
- arranging the sensors in the wellbore surveillance system according to the in
vention in the cavities.
The method may further comprise the step of positioning a tool downhole outside
a sensor in order to transfer fluid reservoir information data from the sensor to
the tool.
In addition, the method may further comprise the steps of loading power from
the tool to the sensor, transmitting a signal by means of the transmitter or pro
viding a current from the first electrode, receiving the signal by means of the receiver
or receiving the current by means of the second electrode, transforming
the signal or current into data, and transferring data from the sensor to the tool.
Furthermore, the present invention relates to a production optimising method,
comprising the steps of:
- transmitting a first signal by means of a first transmitter of the sensors in the
wellbore surveillance system according to the invention,
- receiving the first signal by means of several receivers,
- transforming the first signal into data,
- transferring data from the sensor to a neighbouring sensor and to communica
tion devices all the way to surface,
- transmitting a second signal by means of a second transmitter of the sensors at
a predetermined period of time from the transmission of the first signal,
- receiving the second signal by means of several receivers,
- transforming the second signal into data, and
- transferring data from the sensor to a neighbouring sensor and to communica
tion devices all the way to surface.
Said production optimising method may further comprise the steps of:
- exciting the formation by transmitting acoustic waves into the formation by
means of several sensors at a time to enhance production of fluid into the wellbore,
- measure an impact of the exciting of the formation by transmitting a signal by
means of one transmitter of the sensors,
- receiving the signal by means of several receivers,
- transforming the signal into data,
- transferring data from the sensor to a neighbouring sensor and to communication
devices all the way to surface.
Also, the production optimising method according to invention may further com
prise the steps of lowering a logging tool into the casing and logging the content
of gas, oil and/or water in the fluid in the casing.
Finally, the production optimising method according to the invention may further
comprise the steps of storing data from the sensors of several wells and process
ing the data into a three-dimensional model of the formation with regard to the
content of gas, oil and/or water in the formation.
Brief description of the drawings
The invention and its many advantages will be described in further detail below
with reference to the accompanying schematic drawings, which for the purpose of
illustration show some non-limiting embodiments and in which
Fig. 1 shows a wellbore surveillance system arranged in a casing downhole,
Fig. 2 shows a sensor according to the invention,
Fig. 3 shows another embodiment of the sensor,
Fig. 4 shows yet another embodiment of the sensor,
Fig. 5 shows yet another embodiment of the sensor,
Fig. 6 shows yet another embodiment of the sensor,
Fig. 7 shows a partial view of the system,
Fig. 8 shows a partial view of another embodiment of the system, and
Fig. 9 shows yet another embodiment of the system.
All the figures are highly schematic and not necessarily to scale, and they show
only those parts which are necessary in order to elucidate the invention, other
parts being omitted or merely suggested.
Detailed description of the invention
Fig. 1 shows a wellbore surveillance system 1 for obtaining fluid reservoir information
data. When the formation 4 is drained of oil, the oil layer decreases, and
the water becomes dominating. The oil runs up through a production casing 2,
and eventually, the water will enter into the production casing and disturb the
production of oil. In order to prevent the water from destroying the oil produc
tion, it is desirable to obtain information about the fluid reservoir and the amount
and position of gas, oil and water while draining hydrocarbons from an oil or gas
field. In order to be able to obtain such data, the system comprises at least two
sensors 5. One sensor 5 sends out a signal 7 in the formation 4, and the re
sponse 29 is received by the other sensor or the same sensor. Having several
sensors 5 makes it possible to obtain more detailed information about the reservoir
by comparing the data from one sensor 5 with the data from another sensor.
The system shown in Fig 1 comprises eight sensors 5 arranged with a mutual d is
tance between them and spread out along the substantially horizontal part of the
casing 2.
When the signal 7 passes the different layers of oil, gas and water, it changes,
and these are the changes detected by the sensors 5 as a response. In order to
analyse the data obtained by the sensors 5, a downhole tool 13 is lowered into
the casing 2. The data is transferred from the sensors 5 to the tool 13, and when
the tool reaches the surface, the data is analysed to obtain a profile of the layers
of water, gas and oil.
The signal 7 transmitted is an acoustic signal, such as the signal used in seismic
analysis. Seismic analysis pertains to waves of elastic energy, such as that
transmitted by P-waves and S-waves, in the frequency range of approximately 1
to 100 Hz. Seismic energy is studied to interpret the composition, fluid content,
extent and geometry of rocks in the subsurface.
The seismic data is analysed when it has been transferred from the tool 13 to an
analysis system subsurface. The seismic data can be used for modelling geo
physical attributes and shapes or a geologic causal model of all rock properties,
such as temperature, pressure, velocity, viscosity, etc. Furthermore, the data can
be used for determining petrophysical effects and for indentifying fluid traps, reserves,
recovery and risk.
The tool 13 may also be connected with a wireline 16 by means of which the data
is transferred to the surface. In this way, the tool can stay in the casing over a
longer period of time, even during production, and the data is sent to the surface
almost immediately after it has been transferred to the tool 13. The tool 13 is
powered by the wireline, but may also be powered by a battery 17.
As can be seen in Fig. 1, the tool 13 has wheels 23 for driving the tool forward in
the casing 2, and when the tool reaches a position opposite a sensor 5, the data
is unloaded. Subsequently, the tool 13 moves on to the next sensor 5 to unload
data from that sensor and so forth.
The sensor 5 has a transmitter 6 for transmitting a first signal 7 and a receiver 8
for receiving the first signal. The receiver 8 in a first sensor 5 receives both the
response of a signal 7 sent from the transmitter 6 of the first sensor 5 and the
response of a signal sent from the transmitter of a second sensor. Furthermore,
the sensor 5 comprises a transferring device 9 to be able to transfer data away
from the sensor. The sensor 5 is arranged in the casing wall 30 in a bore. The
sensor 5 is fastened in the bore by means of threads or snap-fit fasteners.
The sensor 5 of Fig. 2 is powered by the tool 13 when it is positioned opposite
the sensor in the casing 2. While the tool 13 powers the sensor 5, the sensor is
able to transmit and receive signals 7 to obtain fluid reservoir information, and
the information received from the receiver 8 is transferred to the tool 13 as it is
received by the receiver. Then, the tool 13 moves to the next sensor 5, and the
operation is repeated.
The sensor 5 in Fig. 3 comprises a microchip 12, such as a microcontroller, for
transforming the response received by the receiver 8 into digital data. The micro
controller comprises static RAM for storing the data. The sensor 5 comprises a
transferring device 9 for transferring the data to the tool 13, which in this embodiment
comprises an inductive coupling 19 matching an inductive coupling 20
of the tool 13 for transferring the data by means of inductance. The sensor 5 also
has a battery 15 for powering the sensor over a period of time. In this way, the
sensor 5 is able to perform measurements on the fluid reservoir without the tool
13 being present. The sensor 5 is programmed, e.g. by means of a timer, to conduct
a measurement each time a predetermined period of time has passed and to
store the data until it can be transferred to the tool 13 or another device.
As shown in Fig. 4, the sensor 5 comprises a wireless communication means 25
for communicating wirelessly with another sensor, the tool 13 or another communication
device. The sensor 5 in Fig. 4 has two electrodes 10, 11 instead of a
transmitter 6 and a receiver 8. The electrodes 10, 11 are used for resistivity or
conductivity logging or measurements. When measuring the resistivity, a current
is passed between the two electrodes, and the potential drops between them
provide the resistivity of the fluid present in the formation 4. When measuring
the conductivity, a current is induced in the formation, and the capacity to carry
the current is observed. By resistivity or conductivity measurement is meant the
response measured by the sensor 5, e.g. the capacity or the potential drop.
In Figs. 2-4, the sensor 5 is arranged in a through-hole in the casing 2, but the
sensor may also be positioned in a cavity in the casing, as shown in Fig. 5. When
the sensor 5 is arranged in only part of the casing 2, the sensor itself does not
have to withstand the pressure difference between the annulus and the inside of
the casing.
The sensor 5 of Fig. 5 comprises a battery 15, an inductive coupling 19 and a
processor 2 1 in which the memory and a communication means in the form of an
input/output interface are arranged. The inductive coupling 19 and the battery 15
may be arranged in one unit. The processor 2 1 may also comprise a radio f re
quency identification device (RFID) to be read by a radio frequency identification
reader in the communication device 26 of the tool 13.
In Fig. 6, the system also comprises a valve 31, such as an inflow control valve,
arranged adjacent to the sensor 5, enabling signals 7 from the sensor to close
the valve if measurements show that the water layer is too close to the sensor
and thereby the valve. In this way, the valve 3 1 is shut off before letting water
into the casing 2. The tool 13 of the system 1 moves inside the casing 2 in order
to read data from the sensors 5 and subsequently transfer the data to the sur
face. The tool 13 in Fig. 7 comprises wheels 23 for moving within the casing 2,
but may as well comprise other driving means, such as a caterpillar track, legs or
similar means. The tool 13 is powered through a wireline 16 for powering a motor
driving a pump and thereby the wheels 23. The tool 13 comprises a communica
tion device 14 for transferring data from the sensor 5. When the communication
device 14 is positioned opposite the sensor 5, the data can be transferred.
The tool of Fig. 7 also comprises a powering device 18 for powering the sensor, if
needed. If the sensor 5 does not have its own power, the tool 13 can transfer
power to the sensor, which then performs a measurement, and the data is thus
transferred to the tool 13 without being stored in the sensor first. In this way, the
sensor 5 can be a very simple sensor with very few components. One way of
transferring power to the sensor 5 is to use an inductive coupling 20 interacting
with an inductive coupling 19 in the sensor 5. The power may also be transferred
to the sensor 5 in another suitable way, such as by mean of microwaves, infrared
light or lasers.
The tool 13 may also hold its own power by comprising a battery 17, as shown in
Fig. 8. In this event, the tool 13 may stay in the casing 2 for a period of time
when all the sensors 5 have been read several times and then emerge to the sur
face for data unloading. The legs holding the wheels 23 have been retracted in
the tool of Fig. 8, enabling the tool to rest against the inner surface of the casing
2 and thus against the outer surface of the sensor 5. This facilitates more efficient
transferral of data from the sensor 5 and/or power to the sensor. If needed,
the tool 13 may have a connection means for providing a direct electrical connec
tion with the sensor 5.
In Fig. 9, the system 1 comprises several communication devices 26 distributed
along the casing 2 from the last sensor 5 to the top of the well. In this way, the
wireless communication means 25 of the sensors 5 can transfer data to the next
sensor or to the communication device 26 if the communication device is next in
line. The communication device 26 then communicates the data to the next
communication device and so forth until the data reaches to top of the casing 24
or well. By having the communication devices 26, a tool 13 is not needed for ob
taining the data in each sensor 5.
The wireless communication may occur by means of radio frequency communica
tion, electromagnetic communication, WIFI, or by acoustic waves transmitted
through the casing wall.
As can be seen in Fig. 10, the wellbore surveillance system may further comprise
a second casing 50 arranged in a second wellbore and comprising a plurality of
sensors for measuring a content of gas, oil and/or water in the formation, which
are arranged at least partly in the casing wall of the second casing at a distance
from each other. In this way, a first signal 7 transmitted by one transmitter 6 in a
sensor 5 in the first casing 2 can be received by a receiver in a sensor in the sec
ond casing 50. The signal has thus passed through the formation about which
knowledge of the content of gas, oil and/or water is desired, and a system having
sensors in two neighbouring casings provides more accurate data than a system
having only one casing 2. The second casing 50 also comprises several communication
devices 26 distributed along the casing 2 from the last sensor 5 to the top
of the well.
In the event that the transmitter in the sensors is not sufficient to transmit a
strong enough signal for the receivers to receive, a tool 13 may be submerged
into a casing 2 as shown in Fig. 11. In order to generate a strong signal, the tool
comprises an acoustic transmitter 53 comprising a weight 4 1 which is rotated by
means of a rotatable shaft 54 to abut the casing wall and in this way transmit
acoustic waves into the formation. The shaft is rotated by means of a motor 55
arranged in the tool housing. The tool comprises an anchor section 40 having anchors
projecting radially from the tool housing to anchor the tool in an eccentric
manner in the casing so that the distance from the tool housing to the casing wall
in one direction is smaller than the distance from the tool housing to the casing
wall in another direction opposite the one direction. In this way, the centre axis
of the tool is offset in relation to the centre axis of the casing.
When the weight is rotated by the shaft, the weight hammers into the casing wall
once along the inner circumference of the casing, generating one acoustic signal
per revolution of the shaft. In this way, a pattern of acoustic signals is generated
which is recognisable by the sensors in the first casing and/or in the second cas
ing 50. In another embodiment, the tool comprises a hammer generating the
acoustic signal by means of a motor.
The signals are low frequency acoustic or sonic signals at a frequency of 1 Hz-
100 kHz, preferably 10-50 kHz, and more preferably 15-35 kHz.
In Fig. 12, the signal transmitted into the formation is provided by a hammering
device arranged at the surface or the seabed. The hammering device 5 1 may be
arranged partly in the ground or in the formation. The signal of the hammering
device is thus received by sensors in both casings or in one casing alone. The
signal received in the receivers of the sensors is thus not a signal which has t rav
elled to the surface or seabed before being received in the sensors. Before being
received in the receivers, the signal has only travelled more or less directly
through the formation, resulting in a more accurate result.
As shown in Figs. 2-6, the sensors are arranged in an opening in the inner face of
the wall of the casing or a through-hole in the wall of the casing. The sensors are
easily installed after completing the well by making a hole in the casing wall and
inserting the sensor in that hole. The sensors may thus be arranged in the wall of
the casing, forming part of an outer face of the casing and in contiguity with the
well fluid and/or the formation. If the casing is cemented in, the sensors do not
have to extend beyond the outer face of the casing, but if the casing is surrounded
by an annulus, the sensors may have to extend from the inner face of
the casing and into the formation surrounding the casing, and thus the axial ex
tension of the sensors are longer than the smallest thickness of the casing wall.
When the signal is an acoustic signal, the transmitter is an acoustic transmitter
and the receiver is an acoustic receiver 43. The acoustic transmitter 53 comprises
a hammer or a weight 41. In Fig. 13, the acoustic transmitter comprises a motor
44 for pulling the weight 4 1 in one direction and releasing the weight which, by
means of a spring means 45, is forced in a second direction opposite the first d i
rection towards the formation to abut the formation. The weight is forced out
through an opening 48 in a housing 59 of the transmitter and can thus hammer
against the formation, generating an acoustic signal.
The acoustic receiver 43 may be any suitable receiver such as an accelerometer,
a microphone or similar acoustic receiver 43. The receiver may be a low f re
quency receiver of between 10-100 Hz. Not all acoustic receivers are capable of
withstanding a hammering motion from a nearby transmitter without getting seriously
damaged, and in such event, the receiver comprises a motor 44 for pull
ing the acoustic receiver 43 in one direction to ensure that the acoustic receiver
is out of contact with a receiver housing 58 and that the acoustic receiver is sur
rounded by fluid while the weight has hammered against the formation or the
casing. When the transmitter has transmitted its signal, the acoustic receiver is
then forced, by means of a spring means 57, in a second direction opposite the
first direction towards the formation to abut the formation and is consequently
capable of receiving the signal, which is as illustrated by a dotted line in Fig. 13.
The motors of the transmitters or the receivers pull the weight or the acoustic receiver
in one direction by means of a rotating shaft 46 which is rotated into the
motor for pulling the weight or the acoustic receiver and forced in the opposite
direction by a spring means 57 arranged between the weight or the acoustic re
ceiver and the respective motor. The receiver comprises a tapering opening 47 to
guide the acoustic receiver when forced towards the formation. Instead of a motor,
an electromagnet may be arranged so when activated, the electromagnet
pulls in the acoustic receiver or the weight.
The transmitter and the receiver are electronically connected via an electronic
control 49 and they are in turn electronically connected via an electronic control
49 to a transferring device 9 for transferring data from this sensor to a
neighbouring sensor in order to get the data upwards to the communication de
vices 26 and thus up to surface. As can be seen in Fig. 13, the sensor extends
into the formation through the casing wall and the annulus or wellbole 3.
The communication devices 26 distributed along the casing can thus also be used
for sending control signals down to the sensors in order to control which t rans
mitter is transmitting a signal. In another embodiment, the sensors comprise a
timer for controlling when a transmitter is to send a signal and when the receiv
ers are to receive that signal. The sensors may be equipped with timers with programmed,
predetermined intervals prescribing when to activate the sensor and
when to also activate the transmitter of that sensor. The sensors may thus be
pre-programmed prior to installation following a surveillance plan according to
which the sensors are activated once a year, half a year or whatever is appropri
ate. In this way, it is not necessary to submerge a tool in order to activate the
sensors. Instead, the sensors activate themselves according to their program
ming and then send their data up to surface.
In Fig. 1, the sensors 5 are arranged in the casing wall 30 so that only one sen
sor is arranged in the same circumferential plane of the casing. The sensors 5
may also be arranged in the same circumferential plane of the casing 2 and have
a circumferential distance to one another, as shown in Fig. 9.
The wellbore surveillance system may furthermore be used as formation logging
method comprising the steps of transmitting a first signal by means of a first
transmitter of one sensor, receiving the first signal sent by that sensor by means
of several receivers in other sensors. Subsequently, the first signal is transformed
into data and the data is transferred from the sensor to a neighbouring sensor.
This step of transferring data is repeated until the data reaches the sensor closest
to the top of the well, and then that sensor transfers the data to a communica
tion device which again transfers the data to the next communication device all
the way to surface. While doing so, a second signal is transmitted by means of a
second transmitter of the sensors at a predetermined period of time from the
transmission of the first signal, which is received by means of several receivers,
and subsequently the data is transformed and sent to the surface in the same
way as the first signal. By receiving the same signal in several receivers, the data
can be processed so that a representation of how the oil, gas and water lie in
layers or zones in the formation can be made.
If the representation of how the oil, gas and water lie in layers or zones in the
formation shows that a zone close to the production zone has an elevated con
centration of water, a production optimising method can be executed. The production
optimisation method comprises the steps of exciting the formation by
transmitting acoustic waves into the formation by means of several sensors s i
multaneously, thereby enhancing production of fluid into the wellbore. In this
way, the formation and the fluid comprised therein are oscillated so that the wa
ter is partially levelled out, if not fully levelled out, thereby aiding the oil in entering
the production zone of the casing, thereby displacing the water locally outside
the casing. Subsequently, the impact of the exciting of the formation is measured
by transmitting a signal by means of one transmitter of the sensors, the signal is
received by means of several receivers, and so forth as explained above, to pro
vide a representation of the oil, water and gas layers or zones.
In order to evaluate the impact of the exciting of the formation inside the casing,
a logging tool is lowered into the casing and the content of gas, oil and/or water
in the fluid in the casing is logged or measured, e.g. by means of a capacitance.
In order to present the data, the data from the sensors of several wells are
stored and processed into a three-dimensional model of the formation with regard
to the content of gas, oil and/or water in the formation. All data have a time
stamp indicating at which time the signal was received, and from that time
stamp, the data can be mapped and a three-dimensional modal can be made
showing a representation of all the data from all the sensors of one or more
wells.
By fluid or well fluid is meant any kind of fluid which may be present in oil or gas
wells downhole, such as natural gas, oil, oil mud, crude oil, water, etc. By gas is
meant any kind of gas composition present in a well, completion, or open hole,
and by oil is meant any kind of oil composition, such as crude oil, an oilcontaining
fluid, etc. Gas, oil, and water fluids may thus all comprise other ele
ments or substances than gas, oil, and/or water, respectively.
By a casing is meant any kind of pipe, tubing, tubular, liner, string, etc. used
downhole in relation to oil or natural gas production.
In the event that the system is not submergible all the way into the casing, a
downhole tractor can be used to push the system all the way into position in the
well. A downhole tractor is any kind of driving tool capable of pushing or pulling
tools in a well downhole, such as a Well Tractor®.
Although the invention has been described in the above in connection with pre
ferred embodiments of the invention, it will be evident for a person skilled in the
art that several modifications are conceivable without departing from the inven
tion as defined by the following claims.
Claims
1. A wellbore surveillance system (1) for obtaining fluid reservoir information
data, such as the position and amount of gas, oil and/or water, while draining
hydrocarbons from an oil or gas field via a casing (2) in a wellbore (3) in a for
mation (4), the casing having a vertical part near a top (25) of the casing and an
inner face, the system comprising:
- a first sensor (5) for measuring a content of gas, oil and/or water in the forma
tion, and
- a second sensor (5) for measuring a content of gas, oil and/or water in the for
mation,
wherein the first and the second sensors are arranged at least partly in a casing
wall of the casing, and the second sensor is arranged at a distance from the first
sensor.
2. A wellbore surveillance system according to claim 1, further comprising a
second casing (50) arranged in a second wellbore and comprising:
- a first sensor (5) for measuring a content of gas, oil and/or water in the forma
tion, and
- a second sensor (5) for measuring a content of gas, oil and/or water in the for
mation,
wherein the first and the second sensors are arranged at least partly in a casing
wall of the second casing, and the second sensor is arranged at a distance from
the first sensor.
3. A wellbore surveillance system according to claim 1 or 2, the first sensor
comprising:
- at least one transmitter (6) of a first signal (7),
- at least one receiver (8) receiving the first signal and/or a second signal,
and
- at least one transferring device (9), and
the second sensor comprising:
- at least one transmitter (6) of the second signal (7),
- at least one receiver (8) of the first signal and/or the second signal, and
- at least one transferring device (9).
4. A wellbore surveillance system according to claims 1-3 , wherein the sen
sors are arranged in an opening in the inner face of the wall of the casing or a
through-hole in the wall of the casing.
5. A wellbore surveillance system according to any of the preceding claims,
wherein the sensors are arranged in the wall of the casing forming part of an
outer face of the casing and in contiguity with the well fluid and/or the formation.
6. A wellbore surveillance system according to any of the preceding claims,
wherein the sensors extend from the inner face of the casing and into the forma
tion surrounding the casing.
7. A wellbore surveillance system according to any of the preceding claims,
wherein the transmitter is an acoustic transmitter.
8. A wellbore surveillance system according to claim 6, wherein the acoustic
transmitter comprises a hammer or a weight (41).
9. A wellbore surveillance system according to claim 7, wherein the acoustic
transmitter comprises a motor (44) for pulling the weight (41) in one direction
and releasing the weight which, by means of a spring means (45), is forced in a
second direction opposite the first direction towards the formation to abut the
formation.
10. A wellbore surveillance system according to any of the preceding claims,
wherein the receiver comprises an acoustic receiver (43).
11. A wellbore surveillance system according to any of the preceding claims,
wherein the acoustic receiver is an accelerometer.
12. A wellbore surveillance system according to any of the preceding claims,
wherein the receiver comprises a motor (44) for pulling the acoustic receiver (43)
in one direction and subsequently forcing the acoustic receiver, by means of a
spring means (57), in a second direction opposite the first direction towards the
formation to abut the formation.
13. A wellbore surveillance system according to any of claims 1-5, wherein the
first sensor comprises a first (10) and a second electrode (11) for providing a
current flowing from the first electrode to the second electrode to conduct a re
sistivity measurement or a conductivity measurement of the formation in order to
determine the content of gas, oil and/or water in the formation.
14. A wellbore surveillance system according to any of the preceding claims,
wherein the sensor comprises a microchip (12) for transforming the signal or the
resistivity or conductivity measurement into data and/or for storing and/or transferring
the data, or for storing a representation of the data.
15. A wellbore surveillance system according to any of the preceding claims,
further comprising at least one tool (13) comprising a communication device (14)
for receiving data from the transferring devices when the tool is in the casing.
16. A wellbore surveillance system according to any of the preceding claims, fur
ther comprising at least one tool (13) comprising an acoustic transmitter (53)
having a weight (41) connected with a rotatable shaft (54) rotated by a motor
(55) in the tool.
17. A wellbore surveillance system according to any of the preceding claims,
wherein the tool further comprises an anchor section (40) for anchoring the tool
within the casing.
18. A wellbore surveillance system according to claim 17, wherein the anchor
section comprises at least a first anchor (56) extending in a first radial direction
of the tool and a second anchor (56) extending in a second direction opposite the
first direction, the extension of the anchors from an outer face of a tool housing
varying so that the tool is anchored in an eccentric relationship to the casing.
19. A wellbore surveillance system according to claims 15-18, wherein the
tool or the communication device comprises a powering device (18) for powering
the sensor.
20. A wellbore surveillance system according to any of claims 15-19, wherein
the powering device and the sensor comprise an inductive coupling (19, 20) for
transferring power from the tool to the sensor through induction.
21. A wellbore surveillance system according to claim 20, wherein the induc
tive coupling is used for transferring data from the sensor to the tool.
22. A wellbore surveillance system according to any of the preceding claims,
wherein the sensor comprises a processor (21) for transforming the signal or the
resistivity or conductivity measurement into data and/or for storing and/or t rans
ferring the data, or for storing a representation of the data.
23. A wellbore surveillance system according to any of the preceding claims,
wherein the signals are generated by acoustics.
24. A wellbore surveillance system according to any of the preceding claims,
wherein the system comprises several communication devices arranged at a pre
determined mutual distance along the casing to the top of the casing, the distance
being determined by the distance over which two devices are capable of
communicating wirelessly with each other.
25. A wellbore surveillance system according to any of the preceding claims,
wherein the system comprises several sensors with wireless communication
means arranged at a predetermined mutual distance along the casing to the top
of the casing, the distance being determined by the distance over which two de
vices are capable of communicating wirelessly with each other.
26. A wellbore surveillance system according to any of the preceding claims,
wherein the system comprises a hammering device (51) arranged at surface or
seabed for transmitting acoustic waves into the formation.
27. A wellbore surveillance system according to any of the preceding claims,
wherein the signal is a low frequency acoustic or sonic signal at a frequency of
1 Hz-100 kHz, preferably 10-50 kHz, and more preferably 15-35 kHz.
28. A downhole tool for reading the data of the sensors in the wellbore sur
veillance system according to any of claims 1-27, wherein the tool comprises
driving means, such as wheels, for driving the tool forward in the casing, and a
communication device according to any of claims 15-27.
29. A method for installing the system according to any of claims 1-27, com
prising the steps of:
- providing a number of cavities at a distance from one another in the casing in
the wellbore, and
- arranging the sensors in the wellbore surveillance system according to any of
claims 1-27 in the cavities.
30. A method according to claim 29, further comprising the steps of:
- positioning a tool downhole outside a sensor in order to transfer fluid reservoir
information data from the sensor to the tool
- loading power from the tool to the sensor,
- transmitting a signal by means of the transmitter or providing a current from
the first electrode,
- receiving the signal by means of the receiver or receiving the current by means
of the second electrode,
- transforming the signal or current into data, and
- transferring data from the sensor to the tool.
31. A production optimising method, comprising the steps of:
- transmitting a first signal by means of a first transmitter of the sensors in the
wellbore surveillance system according to any of claims 1-27,
- receiving the first signal by means of several receivers,
- transforming the first signal into data,
- transferring data from the sensor to a neighbouring sensor and to communication
devices all the way to surface,
- transmitting a second signal by means of a second transmitter of the sensors at
a predetermined period of time from the transmission of the first signal,
- receiving the second signal by means of several receivers,
- transforming the second signal into data, and
- transferring data from the sensor to a neighbouring sensor and to communica
tion devices all the way to surface.
32. A production optimising method according to claim 31, further compris
ing the step of:
- exciting the formation by transmitting acoustic waves into the formation by
means of several sensors at a time to enhance production of fluid into the well
bore,
- measuring an impact of the exciting of the formation by transmitting a signal by
means of one transmitter of the sensors,
- receiving the signal by means of several receivers,
- transforming the signal into data,
- transferring data from the sensor to a neighbouring sensor and to communica
tion devices all the way to surface.
33. A production optimising method according to claim 3 1 or 32, further
comprising the steps of lowering a logging tool into the casing and logging the
content of gas, oil and/or water in the fluid in the casing.
34. A production optimising method according to any of claims 31-33, fur
ther comprising the steps storing data from the sensors of several wells and
processing the data into a three-dimensional model of the formation with regard
to the content of gas, oil and/or water in the formation.