WO1996009461A1 - Apparatus for sensor installation in wells - Google Patents

Apparatus for sensor installation in wells Download PDF

Info

Publication number
WO1996009461A1
WO1996009461A1 PCT/GB1995/002233 GB9502233W WO9609461A1 WO 1996009461 A1 WO1996009461 A1 WO 1996009461A1 GB 9502233 W GB9502233 W GB 9502233W WO 9609461 A1 WO9609461 A1 WO 9609461A1
Authority
WO
WIPO (PCT)
Prior art keywords
sensors
channel means
location
channel
sensor
Prior art date
Application number
PCT/GB1995/002233
Other languages
French (fr)
Inventor
Erhard Lothar Edgar Kluth
Original Assignee
Sensor Dynamics Limited
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Sensor Dynamics Limited filed Critical Sensor Dynamics Limited
Priority to US08/809,947 priority Critical patent/US5804713A/en
Priority to GB9705648A priority patent/GB2307706B/en
Priority to AU35271/95A priority patent/AU3527195A/en
Publication of WO1996009461A1 publication Critical patent/WO1996009461A1/en

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
    • E21B47/135—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D5/00—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable
    • G01D5/26—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light
    • G01D5/32—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light
    • G01D5/34—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells
    • G01D5/353—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre
    • G01D5/35383—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre using multiple sensor devices using multiplexing techniques
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/52—Structural details
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G—PHYSICS
    • G08—SIGNALLING
    • G08C—TRANSMISSION SYSTEMS FOR MEASURED VALUES, CONTROL OR SIMILAR SIGNALS
    • G08C23/00—Non-electrical signal transmission systems, e.g. optical systems
    • G08C23/06—Non-electrical signal transmission systems, e.g. optical systems through light guides, e.g. optical fibres

Definitions

  • the invention relates to apparatus for the installation of sensors in channels.
  • the invention is particularly relevant in the oil industry for installing sensors into oil and gas wells.
  • a wide variety of measurements make it easier to characterise oil and gas reservoirs. These include measurements designed to locate and track fluid fronts within the reservoir and measurements for seismic interrogation of the rock strata within the reservoir.
  • Seismic measurements are normally undertaken with acoustic sensors which can be towed behind ships in large arrays, or positioned on land. More recent work entails lowering high energy acoustic sources into wells and using geophones positioned below the acoustic source v inch monitor the acoustic reflections made by the rock strata. Another recent application has made use of seismic arrays laid in trenches on the ocean floor above the reservoir. For existing reservoirs where measurements are made to locate more oil or gas, geophones may be positioned in other wells for cross-well seismic measurements where the transmission of sound from one well to a variety of wells in the surrounding reservoir is measured. A major problem is that oil or gas production must be stopped in order to take these measurements, which is both expensive and can cause damage to the well.
  • Electric current measurements are also used to characterise the reservoir.
  • Temperature measurements are also used to monitor temperature profiles along oil wells. They are particularly important for determining whether steam or oil is escaping through faults in the rock strata. For this application, the resolution provided by existing optical fibre distributed temperature sensors is not always sufficient.
  • sensors could be deployed into oil and gas wells, cheaply, and at a convenient time after the main equipment installation (pipes, valves, etc) had been completed, so that measurements could be obtained without interrupting the production of oil and/or gas. It could also reduce the need for specialist personnel to be present at the time of well completion, when space in the vicinity of the well-head can be very restricted. If apparatus were available to achieve this, the availability of a plentiful and readily obtainable supply of information about fluid fronts and seismic data would dramatically improve the economics of reservoir management. Costs of production would be reduced, while the amount of recoverable oil would increase.
  • An aim of the present invention is to provide apparatus for the installation of sensors in channels.
  • a further aim is to provide apparatus which will allow sensors to be deployed into oil and gas wells, both during the completion stages of the wells, or at some convenient time thereafter.
  • apparatus for the installation of sensors in channels comprising first channel means and one or more sensor location means comprising one or more turn means.
  • the first channel means may be a length of hydraulic conduit or chemical injection line.
  • the turn means may comprise a loop of hydraulic conduit either in plane, or in a spiral.
  • the location means may comprise several loops of hydraulic conduit.
  • the turn means is wrapped around second channel means.
  • the second channel means may be production tubing in an oil or gas well through which oil or gas is extracted from a reservoir.
  • each location means comprising several (typically three to twenty) turn means whose spacing is comparable to the diameter of the second channel means.
  • Such an apparatus would allow an array of optical fibre acoustic sensors to be pumped down the first channel means until they were located in the location means, with the effective centres of each sensor in the array positioned in a spiral around the location means.
  • Each acoustic sensor operates as a hydrophone, and each array of hydrophones may be steered electronically in order to detect acoustic signals from desired directions.
  • An alternative approach would be to deploy suitably precoiled hydrophones along a conduit.
  • the apparatus as a whole, comprising several hydrophone arrays strung down the second channel means, is an electronically steerable acoustic array capable of gathering data for seismic surveys.
  • the array or arrays can either be installed in or around the first channel means and installed during well completion (ie while completing the installation of equipment into the oil or gas well), or pumped into the second channel means at a convenient time thereafter.
  • the sensor array can be pumped through the second channel means using a variety of fluids such as water, hydraulic oil, or gas.
  • the sensor array may be designed to resemble an optical fibre cable having a diameter of around 250um to 1 OOOum such that it can be readily pumped through conveniently sized hydraulic control line such as 1/4" (6 mm) or 3/8" (10 mm) outer diameter, at a water flow rate of around 0.5 to 3 litres per minute. If larger diameter structures are used, then fluid flow can still be used to effect transport, by employing a technique which is used to extract 1/4" (6 mm) control lines from coiled tubing of 2 1/2" (65 mm) diameter.
  • the array can be interrogated using a variety of known techniques.
  • fibre optic current sensors may be used.
  • the sensing element may comprise one or more loops of optical fibre through which light is passed. Electric current flowing through the loop results in Faraday rotation which can be measured by suitable instrumentation.
  • each location means measuring the total electric current flowing through the production string at the desired location.
  • the apparatus could be used to take both measurements simultaneously, with the sensors either being pumped down together, or one after the other.
  • the preferred choice of material for the hydraulic conduit used in this application is such that it will not shield the magnetic fields generated by the electric current from the optical fibre inside.
  • the apparatus can be simplified if electric current measurement only is desired, as the need to position the first channel means accurately in relation to the second channel means is less significant.
  • the resolution of the profile along an oil well can be increased by wrapping the first channel means around the production tubing.
  • the apparatus described above achieves this aim.
  • the same apparatus can therefore be used for acoustic arrays and/or electric current monitoring, and/or for increasing the spatial resolution of temperature profile measurements.
  • the first channel means may be coiled around the production tubing where it penetrates these strata.
  • the fibre sensor for the temperature profiling measurement can be pumped in after well completion.
  • Figure 1 is a diagram of an embodiment of the present invention showing first channel means
  • Figure 2 is a diagram of an embodiment of the present invention where first channel means is wrapped around second channel means.
  • Figure 3 is a diagram of an embodiment of the present invention showing a typical assembly of the apparatus in an oil or gas well
  • Figure 4 is a diagram of an embodiment of the present invention configured as an electric current sensor.
  • Figure 5 is a diagram of an embodiment of the present invention configured as a temperature sensor.
  • first channel means 1 comprising one or more location means 2.
  • the location means 2 are fabricated by configuring first channel means 1 into one or more turn means 3.
  • first channel means 1 is such that the location means 2 encompasses second channel means 21.
  • Figure 3 shows hydraulic control line 31 of convenient size (6mm or 10mm) attached, for example by straps, to the main production tube 32 of an oil or gas well.
  • the production tube extends down into the reservoir, 42.
  • the control line enters the well via the well-head 33 and may lie linearly along the production tube down to the depth at which the first location means 2 is situated.
  • the control line 31 then spirals around the production tube 31 one or more turns 34.
  • Additional location means 35 all comprising of one, or more, turns of the control line around the production tube, are positioned at intervals further along the production tube.
  • the control line then returns to the surface in a linear fashion 36 along the production tube, where it exits the well via the well-head.
  • the return path may follow a similar path to the downward path, or it may return by an altogether different route, for example inside the production tubing 32.
  • the sensors 37 are positioned within the hyoraulic control line, as shown in the detail at 38, having been deployed by pumping a suitable
  • SURSTi- ⁇ ⁇ SHEET (RULE 26) fluid through the line. After deployment, the sensors and their interconnecting cable extend along the length of the control line.
  • the hydraulic control line is connected, via appropriate high pressure seals, to the electronic interrogation system 41 at which measurements are taken.
  • a linear array of optical fibre current sensors could be used.
  • the sensor measures the line integral of the electric current 100 passing up the production tubing 32, thus multiplying the effect by the number of turns wrapped around the production tube.
  • the coiled regions of the control line and their associated current sensors would probably, but not necessarily, be positioned both above and within the brine layer.
  • the electric current passes along the production tube and is detected when the magnetic field, induced by the moving electric charges, interacts with the sensors in the coiled regions of the control line.
  • the choice of non-magnetic control line material such as a non-magnetic stainless steel, may be important.
  • An optical fibre can also be used as a temperature sensor as shown in figure 5.
  • the whole length of optical fibre in the control line would be a continuous temperature sensor.
  • a pulse of light is launched into the fibre by the electronics contained in the control and interrogation unit 41. This interacts with the atoms, comprising the glass of the fibre along the whole of its length, and stimulates them to emit light with characteristics determined by the local temperature. Some of this light travels back along the fibre to the electronic interrogation system where it is analysed to yield a continuous temperature profile for the whole length of the sensing fibre.
  • Such an interrogation system is the York DTS 80.
  • the resolution of such a sensor along the production tube can be increased by coiling the control line 31, which contains the temperature sensing fibre, more tightly around the production tube 32. Low resolution is achieved at point 200 where the control lines are widely spaced, whereas higher resolution is achieved at point 201 where the coils are more closely spaced.
  • optical fibres can again be used as the sensors.
  • a linear array of optical fibre hydrophones would be deployed by pumping it along the control line such that the effective centre of each sensor in the array is positioned in the coiled region of the control line.
  • the directional sensitivity of the array would be adjusted electronically in the interrogation unit on the surface, in order to detect signals from the desired directions.
  • Acoustic applications which usually benefit from very high bandwidth but relatively low sensitivity, include, among others, sand detection, pump monitoring and fluid monitoring in the reservoir.
  • Seismic arrays on the other hand, need to be very sensitive but are usually narrow bandwidth.
  • Optical fibre sensors can operate in both of the disparate regimes.
  • the apparatus may be acoustic or seismic sensing apparatus, electric current sensing apparatus, or temperature profiling apparatus.

Abstract

Apparatus for the installation of sensors (37) in channels (31), which apparatus comprises first channel means (31) and one or more sensor location means (35) comprising one or more turn means (34).

Description

APPARATUS FOR SENSOR INSTALLATIONS IN WELLS
The invention relates to apparatus for the installation of sensors in channels. The invention is particularly relevant in the oil industry for installing sensors into oil and gas wells.
A wide variety of measurements make it easier to characterise oil and gas reservoirs. These include measurements designed to locate and track fluid fronts within the reservoir and measurements for seismic interrogation of the rock strata within the reservoir.
Seismic measurements are normally undertaken with acoustic sensors which can be towed behind ships in large arrays, or positioned on land. More recent work entails lowering high energy acoustic sources into wells and using geophones positioned below the acoustic source v inch monitor the acoustic reflections made by the rock strata. Another recent application has made use of seismic arrays laid in trenches on the ocean floor above the reservoir. For existing reservoirs where measurements are made to locate more oil or gas, geophones may be positioned in other wells for cross-well seismic measurements where the transmission of sound from one well to a variety of wells in the surrounding reservoir is measured. A major problem is that oil or gas production must be stopped in order to take these measurements, which is both expensive and can cause damage to the well.
Electric current measurements are also used to characterise the reservoir. In particular electric current measurements between one well and a neighbouring well, or between points along the well and points near the top of the well, gives evidence of interconnection of brine within the reservoir. This is an important measurement but it is also difficult to take, as it has to be taken outside the production tubing through which oil and gas flow up from the reservoir.
Temperature measurements are also used to monitor temperature profiles along oil wells. They are particularly important for determining whether steam or oil is escaping through faults in the rock strata. For this application, the resolution provided by existing optical fibre distributed temperature sensors is not always sufficient.
It would be highly advantageous if sensors could be deployed into oil and gas wells, cheaply, and at a convenient time after the main equipment installation (pipes, valves, etc) had been completed, so that measurements could be obtained without interrupting the production of oil and/or gas. It could also reduce the need for specialist personnel to be present at the time of well completion, when space in the vicinity of the well-head can be very restricted. If apparatus were available to achieve this, the availability of a plentiful and readily obtainable supply of information about fluid fronts and seismic data would dramatically improve the economics of reservoir management. Costs of production would be reduced, while the amount of recoverable oil would increase.
An aim of the present invention is to provide apparatus for the installation of sensors in channels. A further aim is to provide apparatus which will allow sensors to be deployed into oil and gas wells, both during the completion stages of the wells, or at some convenient time thereafter.
According to the present invention, there is provided apparatus for the installation of sensors in channels comprising first channel means and one or more sensor location means comprising one or more turn means.
The first channel means may be a length of hydraulic conduit or chemical injection line.
The turn means may comprise a loop of hydraulic conduit either in plane, or in a spiral.
The location means may comprise several loops of hydraulic conduit.
In an embodiment of the present invention, the turn means is wrapped around second channel means.
The second channel means may be production tubing in an oil or gas well through which oil or gas is extracted from a reservoir.
For seismic sensing applications, there are preferably several location means separated by around five to fifty metres, each location means comprising several (typically three to twenty) turn means whose spacing is comparable to the diameter of the second channel means. Such an apparatus would allow an array of optical fibre acoustic sensors to be pumped down the first channel means until they were located in the location means, with the effective centres of each sensor in the array positioned in a spiral around the location means. Each acoustic sensor operates as a hydrophone, and each array of hydrophones may be steered electronically in order to detect acoustic signals from desired directions. An alternative approach would be to deploy suitably precoiled hydrophones along a conduit. This becomes practical when the control line is of suitably larger dimensions as, for example, are found in coiled tubing commonly used in the oil and gas industry. In such an implementation further coils would not be required, and the coiled tubing would not necessarily follow the line of the production tubing. The apparatus as a whole, comprising several hydrophone arrays strung down the second channel means, is an electronically steerable acoustic array capable of gathering data for seismic surveys. The array or arrays can either be installed in or around the first channel means and installed during well completion (ie while completing the installation of equipment into the oil or gas well), or pumped into the second channel means at a convenient time thereafter.
The sensor array can be pumped through the second channel means using a variety of fluids such as water, hydraulic oil, or gas. In a typical application, the sensor array may be designed to resemble an optical fibre cable having a diameter of around 250um to 1 OOOum such that it can be readily pumped through conveniently sized hydraulic control line such as 1/4" (6 mm) or 3/8" (10 mm) outer diameter, at a water flow rate of around 0.5 to 3 litres per minute. If larger diameter structures are used, then fluid flow can still be used to effect transport, by employing a technique which is used to extract 1/4" (6 mm) control lines from coiled tubing of 2 1/2" (65 mm) diameter. The array can be interrogated using a variety of known techniques.
For electric current sensing applications, fibre optic current sensors may be used. The sensing element may comprise one or more loops of optical fibre through which light is passed. Electric current flowing through the loop results in Faraday rotation which can be measured by suitable instrumentation. Clearly the apparatus described for the seismic sensing application can also be used for taking electric current measurements, each location means measuring the total electric current flowing through the production string at the desired location. The apparatus could be used to take both measurements simultaneously, with the sensors either being pumped down together, or one after the other. The preferred choice of material for the hydraulic conduit used in this application is such that it will not shield the magnetic fields generated by the electric current from the optical fibre inside. The apparatus can be simplified if electric current measurement only is desired, as the need to position the first channel means accurately in relation to the second channel means is less significant.
For temperature profile measurements, the resolution of the profile along an oil well can be increased by wrapping the first channel means around the production tubing. The apparatus described above achieves this aim. The same apparatus can therefore be used for acoustic arrays and/or electric current monitoring, and/or for increasing the spatial resolution of temperature profile measurements. Alternatively, if temperature profiling through rock strata of interest is required, then the first channel means may be coiled around the production tubing where it penetrates these strata. The fibre sensor for the temperature profiling measurement can be pumped in after well completion.
Embodiments of the invention will now be described solely by way of example and with reference to the accompanying drawings in which:
Figure 1 is a diagram of an embodiment of the present invention showing first channel means; and
Figure 2 is a diagram of an embodiment of the present invention where first channel means is wrapped around second channel means.
Figure 3 is a diagram of an embodiment of the present invention showing a typical assembly of the apparatus in an oil or gas well Figure 4 is a diagram of an embodiment of the present invention configured as an electric current sensor.
Figure 5 is a diagram of an embodiment of the present invention configured as a temperature sensor.
With reference to Figure 1 , there is provided first channel means 1 comprising one or more location means 2. The location means 2 are fabricated by configuring first channel means 1 into one or more turn means 3.
With reference to Figure 2, first channel means 1 is such that the location means 2 encompasses second channel means 21.
Figure 3 shows hydraulic control line 31 of convenient size (6mm or 10mm) attached, for example by straps, to the main production tube 32 of an oil or gas well. The production tube extends down into the reservoir, 42. The control line enters the well via the well-head 33 and may lie linearly along the production tube down to the depth at which the first location means 2 is situated. The control line 31 then spirals around the production tube 31 one or more turns 34. Additional location means 35 all comprising of one, or more, turns of the control line around the production tube, are positioned at intervals further along the production tube. The control line then returns to the surface in a linear fashion 36 along the production tube, where it exits the well via the well-head. Alternatively the return path may follow a similar path to the downward path, or it may return by an altogether different route, for example inside the production tubing 32.
The sensors 37 are positioned within the hyoraulic control line, as shown in the detail at 38, having been deployed by pumping a suitable
SURSTi-π π SHEET (RULE 26) fluid through the line. After deployment, the sensors and their interconnecting cable extend along the length of the control line.
The hydraulic control line is connected, via appropriate high pressure seals, to the electronic interrogation system 41 at which measurements are taken.
With reference to figure 4, for electric current sensing applications, a linear array of optical fibre current sensors could be used. In each loop of the control line the sensor measures the line integral of the electric current 100 passing up the production tubing 32, thus multiplying the effect by the number of turns wrapped around the production tube. In order to monitor the electric current passing up the production tube from, for example, producing layers within the reservoir which may contain brine, the coiled regions of the control line and their associated current sensors would probably, but not necessarily, be positioned both above and within the brine layer. The electric current passes along the production tube and is detected when the magnetic field, induced by the moving electric charges, interacts with the sensors in the coiled regions of the control line. In this application the choice of non-magnetic control line material, such as a non-magnetic stainless steel, may be important.
An optical fibre can also be used as a temperature sensor as shown in figure 5. In this case the whole length of optical fibre in the control line would be a continuous temperature sensor. A pulse of light is launched into the fibre by the electronics contained in the control and interrogation unit 41. This interacts with the atoms, comprising the glass of the fibre along the whole of its length, and stimulates them to emit light with characteristics determined by the local temperature. Some of this light travels back along the fibre to the electronic interrogation system where it is analysed to yield a continuous temperature profile for the whole length of the sensing fibre. Such an interrogation system is the York DTS 80. The resolution of such a sensor along the production tube can be increased by coiling the control line 31, which contains the temperature sensing fibre, more tightly around the production tube 32. Low resolution is achieved at point 200 where the control lines are widely spaced, whereas higher resolution is achieved at point 201 where the coils are more closely spaced.
For acoustic and seismic applications optical fibres can again be used as the sensors. In these cases a linear array of optical fibre hydrophones would be deployed by pumping it along the control line such that the effective centre of each sensor in the array is positioned in the coiled region of the control line. The directional sensitivity of the array would be adjusted electronically in the interrogation unit on the surface, in order to detect signals from the desired directions. Acoustic applications, which usually benefit from very high bandwidth but relatively low sensitivity, include, among others, sand detection, pump monitoring and fluid monitoring in the reservoir. Seismic arrays, on the other hand, need to be very sensitive but are usually narrow bandwidth. Optical fibre sensors can operate in both of the disparate regimes.
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. Depending upon the use of the apparatus of the invention, the apparatus may be acoustic or seismic sensing apparatus, electric current sensing apparatus, or temperature profiling apparatus.

Claims

C LA I MS
1. Apparatus for the installation of sensors in channels, which apparatus comprises first channel means and one or more sensor location means comprising one or more turn means.
2. Apparatus according to claim 1 in which the first channel means is a length of hydraulic conduit or chemical injection line.
3. Apparatus according to claim 1 or claim 2 in which the turn means comprises a loop of hydraulic conduit either in plane, or in a spiral.
4. Apparatus according to any one of the preceding claims in which the location means comprises loops of hydraulic conduit .
5. Apparatus according to any one of the preceding claims in which the turn means is wrapped around second channel means.
6. Apparatus according to claim 5 in which the second channel means is production tubing in an oil or gas well through which oil or gas is extracted from a reservoir.
7. Apparatus according to claim 5 or claim 6 in which there are several separate location means, each location means comprising several turn means whose spacing is comparable to the diameter of the second channel means.
8. Apparatus according to claim 7 in which there are from 3 to 20 of the turn means for each location means.
9. Apparatus according to any one of the preceding claims and including one or more sensors.
10. Apparatus according to claim 8 and claim 9 in which the sensors are in the form of an array of optical fibre acoustic sensors, and in which the array of optical fibre acoustic sensors s provided in the first channel means and located in the location means, with the effective centres of each sensor in the array positioned in a spiral around the location means.
11. Apparatus according to claim 9 in which the or each sensor is a fibre optic current sensor.
12. Apparatus according to any one of the preceding claims in which the first channel means is wrapped around production tubing.
SUBSTITUTE SHE^T (PULE 26)
13. Apparatus according to any one of claims l-ll in which the first channel means is coiled around production tubing where it penetrates rock strata during use of the apparatus.
SUBSTITUTE SHEET (RULE 26
PCT/GB1995/002233 1994-09-21 1995-09-20 Apparatus for sensor installation in wells WO1996009461A1 (en)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US08/809,947 US5804713A (en) 1994-09-21 1995-09-20 Apparatus for sensor installations in wells
GB9705648A GB2307706B (en) 1994-09-21 1995-09-20 Apparatus for sensor installation in wells
AU35271/95A AU3527195A (en) 1994-09-21 1995-09-20 Apparatus for sensor installation in wells

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB9419006.3 1994-09-21
GB9419006A GB9419006D0 (en) 1994-09-21 1994-09-21 Apparatus for sensor installation

Publications (1)

Publication Number Publication Date
WO1996009461A1 true WO1996009461A1 (en) 1996-03-28

Family

ID=10761669

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/GB1995/002233 WO1996009461A1 (en) 1994-09-21 1995-09-20 Apparatus for sensor installation in wells

Country Status (4)

Country Link
US (1) US5804713A (en)
AU (1) AU3527195A (en)
GB (2) GB9419006D0 (en)
WO (1) WO1996009461A1 (en)

Cited By (15)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1998050681A1 (en) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
US5992250A (en) * 1996-03-29 1999-11-30 Geosensor Corp. Apparatus for the remote measurement of physical parameters
WO2000011317A1 (en) * 1998-08-25 2000-03-02 Baker Hughes Incorporated Method of using a heater with a fiber optic string in a wellbore
GB2310280B (en) * 1996-02-16 2000-09-20 Sensor Dynamics Ltd Apparatus for extracting at least one of oil, gas, sulphur or geothermal energy from below ground
GB2354583A (en) * 1996-10-09 2001-03-28 Baker Hughes Inc Method of obtaining improved geophysical information about earth formations
US6253848B1 (en) 1995-02-09 2001-07-03 Baker Hughes Incorporated Method of obtaining improved geophysical information about earth formations
EP0911483A3 (en) * 1997-10-27 2002-06-05 Halliburton Energy Services, Inc. Well system including composite pipes and a downhole propulsion system
US6532839B1 (en) 1996-03-29 2003-03-18 Sensor Dynamics Ltd. Apparatus for the remote measurement of physical parameters
US6769805B2 (en) 1998-08-25 2004-08-03 Sensor Highway Limited Method of using a heater with a fiber optic string in a wellbore
US7040390B2 (en) 1997-05-02 2006-05-09 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
AU2005203588B2 (en) * 1997-05-02 2008-12-04 Baker Hughes Incorporated Wellbores utilizing fibre optic-based sensors and operating devices
US20110088462A1 (en) * 2009-10-21 2011-04-21 Halliburton Energy Services, Inc. Downhole monitoring with distributed acoustic/vibration, strain and/or density sensing
US8573313B2 (en) 2006-04-03 2013-11-05 Schlumberger Technology Corporation Well servicing methods and systems
US8584519B2 (en) 2010-07-19 2013-11-19 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system

Families Citing this family (61)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6464021B1 (en) * 1997-06-02 2002-10-15 Schlumberger Technology Corporation Equi-pressure geosteering
US5986749A (en) 1997-09-19 1999-11-16 Cidra Corporation Fiber optic sensing system
US6009216A (en) * 1997-11-05 1999-12-28 Cidra Corporation Coiled tubing sensor system for delivery of distributed multiplexed sensors
EP1090274B1 (en) 1998-06-26 2017-03-15 Weatherford Technology Holdings, LLC Fluid parameter measurement in pipes using acoustic pressures
US6305227B1 (en) 1998-09-02 2001-10-23 Cidra Corporation Sensing systems using quartz sensors and fiber optics
US6137621A (en) * 1998-09-02 2000-10-24 Cidra Corp Acoustic logging system using fiber optics
CA2644328A1 (en) 1998-12-17 2000-06-22 Chevron U.S.A. Inc. Apparatus and method for protecting devices, especially fibre optic devices, in hostile environments
US6271766B1 (en) * 1998-12-23 2001-08-07 Cidra Corporation Distributed selectable latent fiber optic sensors
US6227114B1 (en) 1998-12-29 2001-05-08 Cidra Corporation Select trigger and detonation system using an optical fiber
US6766703B1 (en) 1999-02-05 2004-07-27 Sensor Dynamics Limited Apparatus and method for enhancing remote sensor performance and utility
GB9902596D0 (en) * 1999-02-05 1999-03-24 Sensor Dynamics Ltd Apparatus and method for protecting sensors and cables in hostile environments
US6644402B1 (en) 1999-02-16 2003-11-11 Schlumberger Technology Corporation Method of installing a sensor in a well
US6209391B1 (en) * 1999-03-11 2001-04-03 Tim Dallas Free fall survey instrument
US6463813B1 (en) 1999-06-25 2002-10-15 Weatherford/Lamb, Inc. Displacement based pressure sensor measuring unsteady pressure in a pipe
NL1012468C2 (en) 1999-06-29 2001-01-02 Ver Bedrijven Van Den Berg Hee Soil probe with optical data transmission.
US6536291B1 (en) 1999-07-02 2003-03-25 Weatherford/Lamb, Inc. Optical flow rate measurement using unsteady pressures
US6691584B2 (en) 1999-07-02 2004-02-17 Weatherford/Lamb, Inc. Flow rate measurement using unsteady pressures
US6581454B1 (en) * 1999-08-03 2003-06-24 Shell Oil Company Apparatus for measurement
AU782553B2 (en) * 2000-01-05 2005-08-11 Baker Hughes Incorporated Method of providing hydraulic/fiber conduits adjacent bottom hole assemblies for multi-step completions
US6601458B1 (en) 2000-03-07 2003-08-05 Weatherford/Lamb, Inc. Distributed sound speed measurements for multiphase flow measurement
US6813962B2 (en) * 2000-03-07 2004-11-09 Weatherford/Lamb, Inc. Distributed sound speed measurements for multiphase flow measurement
US6601671B1 (en) * 2000-07-10 2003-08-05 Weatherford/Lamb, Inc. Method and apparatus for seismically surveying an earth formation in relation to a borehole
US6789621B2 (en) 2000-08-03 2004-09-14 Schlumberger Technology Corporation Intelligent well system and method
US6427529B1 (en) * 2000-09-29 2002-08-06 L.A. Daly Company Instrument for surveying the depth and volume of oil and brine in a static fluid column of an oil well
US6782150B2 (en) 2000-11-29 2004-08-24 Weatherford/Lamb, Inc. Apparatus for sensing fluid in a pipe
US6568481B2 (en) * 2001-05-04 2003-05-27 Sensor Highway Limited Deep well instrumentation
WO2003023451A1 (en) * 2001-09-07 2003-03-20 Input/Output, Inc. Reservoir evaluation apparatus and method
US6698297B2 (en) 2002-06-28 2004-03-02 Weatherford/Lamb, Inc. Venturi augmented flow meter
US6971259B2 (en) * 2001-11-07 2005-12-06 Weatherford/Lamb, Inc. Fluid density measurement in pipes using acoustic pressures
US7059172B2 (en) * 2001-11-07 2006-06-13 Weatherford/Lamb, Inc. Phase flow measurement in pipes using a density meter
US7181955B2 (en) * 2002-08-08 2007-02-27 Weatherford/Lamb, Inc. Apparatus and method for measuring multi-Phase flows in pulp and paper industry applications
US6758271B1 (en) * 2002-08-15 2004-07-06 Sensor Highway Limited System and technique to improve a well stimulation process
US7028543B2 (en) * 2003-01-21 2006-04-18 Weatherford/Lamb, Inc. System and method for monitoring performance of downhole equipment using fiber optic based sensors
US6986276B2 (en) * 2003-03-07 2006-01-17 Weatherford/Lamb, Inc. Deployable mandrel for downhole measurements
US6837098B2 (en) * 2003-03-19 2005-01-04 Weatherford/Lamb, Inc. Sand monitoring within wells using acoustic arrays
US6840114B2 (en) * 2003-05-19 2005-01-11 Weatherford/Lamb, Inc. Housing on the exterior of a well casing for optical fiber sensors
US6957574B2 (en) * 2003-05-19 2005-10-25 Weatherford/Lamb, Inc. Well integrity monitoring system
US6955218B2 (en) * 2003-08-15 2005-10-18 Weatherford/Lamb, Inc. Placing fiber optic sensor line
US6910388B2 (en) * 2003-08-22 2005-06-28 Weatherford/Lamb, Inc. Flow meter using an expanded tube section and sensitive differential pressure measurement
US20080264182A1 (en) * 2003-08-22 2008-10-30 Jones Richard T Flow meter using sensitive differential pressure measurement
US7999695B2 (en) * 2004-03-03 2011-08-16 Halliburton Energy Services, Inc. Surface real-time processing of downhole data
GB2428096B (en) 2004-03-04 2008-10-15 Halliburton Energy Serv Inc Multiple distributed force measurements
US9441476B2 (en) 2004-03-04 2016-09-13 Halliburton Energy Services, Inc. Multiple distributed pressure measurements
US7219747B2 (en) * 2004-03-04 2007-05-22 Halliburton Energy Services, Inc. Providing a local response to a local condition in an oil well
US20050236161A1 (en) * 2004-04-23 2005-10-27 Michael Gay Optical fiber equipped tubing and methods of making and using
US20050248334A1 (en) * 2004-05-07 2005-11-10 Dagenais Pete C System and method for monitoring erosion
US7109471B2 (en) * 2004-06-04 2006-09-19 Weatherford/Lamb, Inc. Optical wavelength determination using multiple measurable features
US7480056B2 (en) * 2004-06-04 2009-01-20 Optoplan As Multi-pulse heterodyne sub-carrier interrogation of interferometric sensors
US20060054316A1 (en) * 2004-09-13 2006-03-16 Heaney Francis M Method and apparatus for production logging
CN101313127A (en) * 2005-11-21 2008-11-26 国际壳牌研究有限公司 Method for monitoring fluid properties
US7503217B2 (en) * 2006-01-27 2009-03-17 Weatherford/Lamb, Inc. Sonar sand detection
US8547539B2 (en) * 2008-09-08 2013-10-01 Schlumberger Technology Corporation System and method for detection of flexible pipe armor wire ruptures
US20100132955A1 (en) * 2008-12-02 2010-06-03 Misc B.V. Method and system for deploying sensors in a well bore using a latch and mating element
GB2511657B (en) 2009-05-27 2014-12-31 Optasense Holdings Ltd Fracture monitoring
US20110083856A1 (en) * 2009-10-08 2011-04-14 Schlumberger Technology Corporation Sensor deployment and retrieval system using fluid drag force
US9417103B2 (en) 2011-09-20 2016-08-16 Schlumberger Technology Corporation Multiple spectrum channel, multiple sensor fiber optic monitoring system
US9976361B2 (en) 2013-02-21 2018-05-22 Halliburton Energy Services, Inc. Method and system for directing control lines along a travel joint
US9410422B2 (en) 2013-09-13 2016-08-09 Chevron U.S.A. Inc. Alternative gauging system for production well testing and related methods
US9624763B2 (en) 2014-09-29 2017-04-18 Baker Hughes Incorporated Downhole health monitoring system and method
US20190129062A1 (en) * 2017-10-27 2019-05-02 Baker Hughes, A Ge Company, Llc Environmental impact monitoring for downhole systems
CA3022394A1 (en) 2018-10-29 2020-04-29 CCI Inc. Pipeline sensor conduit and adhesion method

Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0546892A1 (en) * 1991-12-11 1993-06-16 Institut Francais Du Petrole Method and device for electrically interconnecting apparatuses such as wellbore probes
GB2284257A (en) * 1993-11-26 1995-05-31 Sensor Dynamics Ltd Remote measurement of physical parameters

Family Cites Families (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2301326A (en) * 1939-11-03 1942-11-10 Standard Oil Dev Co Process for obtaining temperature gradients in bore holes
US2824378A (en) * 1953-06-12 1958-02-25 Petroleum Recovery Engineering Apparatus for determining the contour and position of obstructions in wells
US2894200A (en) * 1956-10-26 1959-07-07 Sinclair Oil & Gas Company Subterranean interface locator
US3086167A (en) * 1958-11-13 1963-04-16 Sun Oil Co Bore hole logging methods and apparatus
US4167111A (en) * 1978-05-04 1979-09-11 The United States Of America Is Represented By The Administrator Of The National Aeronautics & Space Administration Borehole geological assessment
US4226288A (en) * 1978-05-05 1980-10-07 California Institute Of Technology Side hole drilling in boreholes
JPS5668443A (en) * 1979-11-12 1981-06-09 Olympus Optical Co Ultrasonic scanner for inspecting body cavity
US4455869A (en) * 1982-06-21 1984-06-26 Broussard Paul P Method for determining borehole or cavity configuration through inert gas interface
US4951677A (en) * 1988-03-21 1990-08-28 Prutech Research And Development Partnership Ii Acoustic imaging catheter and the like
US5097838A (en) * 1989-04-27 1992-03-24 Olympus Optical Co., Ltd. Ultrasonic endoscope
US5626192A (en) * 1996-02-20 1997-05-06 Halliburton Energy Services, Inc. Coiled tubing joint locator and methods

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0546892A1 (en) * 1991-12-11 1993-06-16 Institut Francais Du Petrole Method and device for electrically interconnecting apparatuses such as wellbore probes
GB2284257A (en) * 1993-11-26 1995-05-31 Sensor Dynamics Ltd Remote measurement of physical parameters

Cited By (28)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6253848B1 (en) 1995-02-09 2001-07-03 Baker Hughes Incorporated Method of obtaining improved geophysical information about earth formations
GB2310280B (en) * 1996-02-16 2000-09-20 Sensor Dynamics Ltd Apparatus for extracting at least one of oil, gas, sulphur or geothermal energy from below ground
US6817257B2 (en) 1996-03-29 2004-11-16 Sensor Dynamics Limited Apparatus for the remote measurement of physical parameters
US6532839B1 (en) 1996-03-29 2003-03-18 Sensor Dynamics Ltd. Apparatus for the remote measurement of physical parameters
US5992250A (en) * 1996-03-29 1999-11-30 Geosensor Corp. Apparatus for the remote measurement of physical parameters
GB2354583A (en) * 1996-10-09 2001-03-28 Baker Hughes Inc Method of obtaining improved geophysical information about earth formations
GB2354583B (en) * 1996-10-09 2001-06-06 Baker Hughes Inc Method of obtaining improved geophysical information about earth formations
US6588266B2 (en) 1997-05-02 2003-07-08 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
WO1998050681A1 (en) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
GB2339902A (en) * 1997-05-02 2000-02-09 Baker Hughes Inc Monitoring of downhole parameters and tools utilizing fiber optics
US6268911B1 (en) 1997-05-02 2001-07-31 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
GB2339902B (en) * 1997-05-02 2002-01-23 Baker Hughes Inc Monitoring of downhole parameters
US8789587B2 (en) 1997-05-02 2014-07-29 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
WO1998050680A3 (en) * 1997-05-02 1999-02-04 Baker Hughes Inc Monitoring of downhole parameters and tools utilizing fiber optics
US7201221B2 (en) 1997-05-02 2007-04-10 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
AU2005203588B2 (en) * 1997-05-02 2008-12-04 Baker Hughes Incorporated Wellbores utilizing fibre optic-based sensors and operating devices
WO1998050680A2 (en) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
US7040390B2 (en) 1997-05-02 2006-05-09 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
EP0911483A3 (en) * 1997-10-27 2002-06-05 Halliburton Energy Services, Inc. Well system including composite pipes and a downhole propulsion system
US6769805B2 (en) 1998-08-25 2004-08-03 Sensor Highway Limited Method of using a heater with a fiber optic string in a wellbore
WO2000011317A1 (en) * 1998-08-25 2000-03-02 Baker Hughes Incorporated Method of using a heater with a fiber optic string in a wellbore
US6497279B1 (en) * 1998-08-25 2002-12-24 Sensor Highway Limited Method of using a heater with a fiber optic string in a wellbore
US8573313B2 (en) 2006-04-03 2013-11-05 Schlumberger Technology Corporation Well servicing methods and systems
US20110088462A1 (en) * 2009-10-21 2011-04-21 Halliburton Energy Services, Inc. Downhole monitoring with distributed acoustic/vibration, strain and/or density sensing
US20130091942A1 (en) * 2009-10-21 2013-04-18 Halliburton Energy Services, Inc. Downhole monitoring with distributed acoustic/vibration, strain and/or density sensing
US8584519B2 (en) 2010-07-19 2013-11-19 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US9003874B2 (en) 2010-07-19 2015-04-14 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system

Also Published As

Publication number Publication date
GB9705648D0 (en) 1997-05-07
US5804713A (en) 1998-09-08
GB2307706A (en) 1997-06-04
AU3527195A (en) 1996-04-09
GB9419006D0 (en) 1994-11-09
GB2307706B (en) 1998-04-22

Similar Documents

Publication Publication Date Title
US5804713A (en) Apparatus for sensor installations in wells
CA2830141C (en) Optical fiber based downhole seismic sensor system based on rayleigh backscatter
RU2661747C2 (en) Distributed acoustic measurement for passive range measurement
US7219729B2 (en) Permanent downhole deployment of optical sensors
EP2783189B1 (en) Fluid measurement system and method for determining fluid composition and flow along a conduit
US7740064B2 (en) System, method, and apparatus for downhole submersible pump having fiber optic communications
US8315486B2 (en) Distributed acoustic sensing with fiber Bragg gratings
US6995899B2 (en) Fiber optic amplifier for oilfield applications
US10132955B2 (en) Fiber optic array apparatus, systems, and methods
WO2016020654A1 (en) Monitoring of reservoirs using a fibre optic distributed acoustic sensor
GB2495132A (en) Fluid mixture determination
WO2016209388A1 (en) Continuous beamforming while moving: method to reduce spatial aliasing in leak detection
US20230072270A1 (en) Wireline Optical Fiber Sensing
US20150323700A1 (en) In-Situ System Calibration
US9359833B2 (en) Method for installing multiple fiber optic cables in coiled tubing
WO2014194051A1 (en) Wellbore survey using optical fibers
CA2747368C (en) Permanent downhole deployment of optical sensors

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AM AT AU BB BG BR BY CA CH CN CZ DE DK EE ES FI GB GE HU IS JP KE KG KP KR KZ LK LR LT LU LV MD MG MK MN MW MX NO NZ PL PT RO RU SD SE SG SI SK TJ TM TT UA UG US UZ VN

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): KE MW SD SZ UG AT BE CH DE DK ES FR GB GR IE IT LU MC NL PT SE BF BJ CF CG CI CM GA GN ML MR NE SN TD TG

DFPE Request for preliminary examination filed prior to expiration of 19th month from priority date (pct application filed before 20040101)
121 Ep: the epo has been informed by wipo that ep was designated in this application
WWE Wipo information: entry into national phase

Ref document number: 9705648.5

Country of ref document: GB

Ref document number: 08809947

Country of ref document: US

REG Reference to national code

Ref country code: DE

Ref legal event code: 8642

122 Ep: pct application non-entry in european phase