EP1070196B1 - Vorrichtung und verfahren zur erhöhung der leistung eines fernsensors - Google Patents

Vorrichtung und verfahren zur erhöhung der leistung eines fernsensors Download PDF

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Publication number
EP1070196B1
EP1070196B1 EP00907123A EP00907123A EP1070196B1 EP 1070196 B1 EP1070196 B1 EP 1070196B1 EP 00907123 A EP00907123 A EP 00907123A EP 00907123 A EP00907123 A EP 00907123A EP 1070196 B1 EP1070196 B1 EP 1070196B1
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EP
European Patent Office
Prior art keywords
fluid
control line
barrier
reservoir
sensor
Prior art date
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EP00907123A
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English (en)
French (fr)
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EP1070196A1 (de
Inventor
E. L. E. Kluth
M. P. Varnham
J. R. Clowes
C. M. Crawley
Roy Kutlik
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Sensor Dynamics Ltd
Chevron USA Inc
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Sensor Dynamics Ltd
Chevron USA Inc
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B47/017—Protecting measuring instruments
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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 boreholes or wells
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems

Definitions

  • the current invention pertains to remote sensing devices, and in particular to fibre optic sensors and communication cables used in such sensing devices, more particularly to methods and apparatus for protecting such sensors, communication cables, and conduits containing such sensors and communication cables from damage resulting from the ambient environment at the remote location.
  • Sensors for measuring pressure, temperature and temperature profiles, acoustic pressure waves and vibrations, magnetic fields, electric fields and chemical composition potentially can provide valuable information which can be used to characterise oil and gas reservoirs and for managing the cost effective and safe extraction of hydrocarbon reserves from oil and gas wells. Locating such sensors in appropriate positions inside oil and gas wells using conventional methods is difficult and expensive. It is common practice in the oil industry to use wirelines or slicklines to lower sensors into remote downhole positions. While this type of deployment yields valuable information, the procedures make use of expensive equipment and personnel and require that normal production be interrupted. Slickline and wireline procedures also only provide occasional information.
  • US 5,804,713 discloses apparatus for installing sensors in wells.
  • the sensors may be deployed using a hydraulic control line.
  • fibre optic sensors can be effectively protected to provide a stable response at high temperatures and pressures when the sensors are surrounded by silicone oil. This protection can be extended so that sensors can be deployed in remote locations, including downhole locations in oil and gas wells, where the well bore fluids can be highly corrosive.
  • Liquids cannot support shear stress and therefore do not cause sensors to change their behaviour with changing temperature. For example, polarimetric fibre optic pressure sensors do not become excessively sensitive to changes in temperature.
  • Liquid metals also can readily protect splice regions as well as coated regions of optical fibres and mirrors. Liquid metals can be applied relatively easily to fibres and pumped into capillaries. The use of a liquid interface between the sensor surface and the surrounding capillary further permits the use of multiple coatings on the inside and outside surfaces of the capillary without introducing temperature sensitivity effects in the sensor. In principle the capillary can be used to add protection to cables as well as to sensors.
  • the interior of the control line can be filled with a fluid.
  • This fluid can be in the form of a liquid or gas.
  • a useful liquid is an inert oil such as silicone based oil which can be comparatively stable at common bore hole temperatures and pressures: Silicone based fluids can be obtained commercially which are stable at 250°C and higher. The stability of these fluids varies depending on their purity. It can be difficult to guarantee the purity of such fluids over extended periods unless the fluid is enclosed in a hermetically sealed environment.
  • the control line fluids are allowed to be in direct contact with well bore fluids, then diffusion and convection can occur. This can result in the ingress of water molecules and other species into the control line. In the long term this can result in a hostile environment that attacks even carefully packaged sensors.
  • the current invention discloses methods and apparatus for creating barriers and segments in a control line utilizing fluids or mechanical devices for any and all of the following purposes:
  • the invention includes apparatus and methods for sensing one or more physical parameters at a remote location while minimizing or eliminating contact between reservoir fluids and the like at the remote location and the sensor used to sense the physical parameters.
  • the apparatus isolates the sensor within a control line containing the sensor.
  • apparatus includes a control line containing a communication cable and a sensor in communication with the cable, the sensor being located within the control line proximate the remote location.
  • a sealing device is configured to seal a section of the control line containing the sensor from fluid flow within the control line, the sealing device being configured to be actuated between a sealing state and a non-sealing state.
  • the apparatus further includes a communication device in fluid communication with the remote location and the section of control line containing the sensor.
  • a second control line is in communication with the sealing device and is configured to actuate the sealing device between the sealing state and the non-sealing state.
  • the apparatus is configured to impose a barrier of a fluid between the sensor and the environment at the remote location.
  • the latter apparatus includes a control line containing a communication cable and a sensor in communication with the cable, the sensor being located within the control line proximate the remote location.
  • the apparatus further includes a first tubing having a first end in fluid communication with the control line proximate the sensor.
  • a fluid barrier reservoir containing a barrier fluid is also provided, the fluid barrier having a first opening in fluid communication with a second end of the first tubing, and a second opening in fluid communication with the remote location.
  • One method of the present invention includes a method for chemically isolating a sensor from a location at which a parameter is to be measured by the sensor, the location being in a fluid environment.
  • the method includes emplacing within a control line a sensor in signal communication with a communication cable, the sensor being located within a section of the control line proximate the location at which the parameter is to be measured.
  • the section of the control line containing the sensor is isolated from fluid flow within the control line, and the isolated section of the control line containing the sensor is exposed to the fluid environment at the location.
  • the method can further include emplacing within a control line a plurality of sensors in signal communication with the communication cable, the sensors being located within selected sections of the control line proximate associated selected locations at which the parameter is to be measured.
  • the selected sections of the control line containing the associated sensors are selectively isolated from fluid flow within the control line, and the isolated selected sections of the control line containing the associated sensors are exposed to the fluid environment at the associated locations.
  • Another method of the present invention for chemically isolating a sensor from a location at which a parameter is to be measured by the sensor includes emplacing within a control line a sensor in signal communication with a communication cable, the sensor being located within a section of the control line proximate the location at which the parameter is to be measured.
  • a fluid reservoir is placed in fluid communication with the section of the control line containing the sensor, the fluid reservoir further being placed in fluid communication with the fluid environment.
  • the control line is isolated to prevent passage of fluid out of the control line, and a first fluid is passed into the control line to cause the fluid to flow into the fluid reservoir.
  • the method can further include measuring the volume of the first fluid passed down the control line and into the fluid reservoir, and ceasing flowing of the first fluid into the control line when a sufficient volume of the first fluid has been passed down the control line to fill at least a portion of the fluid reservoir.
  • pressure communication from the well bore to the sensor inside the control line should preferably be such that as little water or well bore fluid can enter the control line. It is important to minimise the possibility of foreign molecules entering the sensor and hence causing drift.
  • Water molecules and OH groups are known to be chemically very aggressive at high temperatures and pressures and well bore fluids vary widely in composition, from well to well and in time. These fluids can be extremely aggressive chemically.
  • a prior art approach that reduces or eliminates the ingress of molecules from well bore into the region where the sensor is located is to interpose a membrane or diaphragm.
  • This approach brings with it a number of disadvantages that can lead to difficulties in acquiring pressure information accurately.
  • the diaphragm or membrane have to respond to small changes in pressure, yet the direct contact with the well bore fluid can result in corrosion or in the scale formation which change the response of the membrane or diaphragm to pressure changes.
  • an alternative approach to reduce or eliminate the ingress of molecules from well bore into the region where the sensor is located is to allow a direct connection between the well bore fluid and the interior of the control line, in such a manner that the well bore fluid is prevented as much as possible from causing undesirable changes in the sensors or cables while allowing the relevant information to be acquired by the sensors.
  • the well bore pressure can be communicated accurately to the sensor through one or more intermediate liquids.
  • the intermediate liquids are selected so that long-term exposure results in minimal change in the sensor. It is also preferable that the intermediate liquid can be easily replaced if contamination or degradation occurs in particularly hostile environments. Preferably this does not require the removal of the sensors and cables in the control line.
  • the composition sensor probe when the composition of the well bore fluid is to be analysed, the composition sensor probe is in direct contact with the well bore fluid. It is preferable that direct contact between well bore fluid and sensor probe is restricted to the time when the measurement takes place and that otherwise the sensor probe is in an environment that does not change or degrade the sensor or cable.
  • direct contact between well bore fluid and sensor probe is restricted to the time when the measurement takes place and that otherwise the sensor probe is in an environment that does not change or degrade the sensor or cable.
  • the end of the fibre optic probe should be directly immersed in the well bore fluid. If this direct contact is maintained permanently then it is likely that the optical fibre will suffer damage.
  • the useful life of the probe is extended if direct contact is only occasional and if an inert fluid surrounds the probe at all other times.
  • An over-pressure well has a downhole pressure that is higher than the pressure exerted by a highway that is entirely filled with fluid. That is, if the control line were to be opened to atmospheric pressure at the wellhead, then fluid will be forced to flow upward in the control line. When the control line is sealed at the upper end of the control line, the fluid at the uppermost point will be at a positive pressure.
  • This over-pressure condition applies typically to oil wells during their early stages of production when the hydrocarbon reservoir pressure is at its highest. If the fluid inside the control line is a liquid that has been carefully de-gassed, then this column of fluid has a high bulk modulus and therefore compresses very little under hydrostatic pressure. Under these conditions a surge in the downhole well pressure, which can occur when the flow rate of the well is decreased or shut off, will not cause significant amounts of well bore fluid to enter the control line.
  • pressure from the well bore can be communicated simply to the sensor inside of the control line by a length of tubing connecting the well bore to the control line.
  • This tubing can be filled with (one or more) liquid metals or other fluids whose composition is such that it causes minimum change in the sensor over the long term. Alternately a combination of fluids may be chosen to form the barrier.
  • the liquid metal or other fluid preferably should not mix readily or react chemically with the constituents of the well bore fluid. The function of this liquid metal or other liquid is to form a barrier to molecules from the well bore fluid and to prevent these from entering the highway and reaching the sensor.
  • the pressure communicating tubing which enables direct pressure communication between the hydrocarbon reservoir fluid and the control line fluid should preferably be arranged so that the well bore fluid contacts the liquid metal from above to prevent gas from rising from the well bore, through the liquid metal column or other fluid or series of fluids. This can be achieved by forming the connecting tubing into an elbow, with the well bore end of the column pointing upward.
  • the current invention thus includes methods and apparatus for creating barriers and segments in a control line utilizing fluids or mechanical devices for any and all of the following purposes:
  • Figure 6 illustrates schematically one example of how these objectives can be achieved, with specific reference to the measurement of pressure at more than one point in a control line.
  • a section of an oil or gas well is shown including a casing 67, a production string 60, a packer 61.
  • the packer separates the annulus between the casing and the production string into two regions - one section above the packer and the other section below the packer.
  • a control line 62 and a separate hydraulic control line 63 are shown in the annulus between the casing and production tubing and both penetrate the packer.
  • the control line 62 is shown as a continuous control line that turns around at a point below the packer 61.
  • Each arrangement includes sealing devices 64, pressure sensor 65 and pressure communication device 66.
  • the pressure communication device 66 preferably includes a facility that allows it to be closed and opened from the surface.
  • the pressure communication device 66 is connected into the well bore fluids inside the production string 60 and can preferably include a barrier function that prevents or minimizes ingress of well bore fluids into the control line region between the two sealing devices 64.
  • the scaling devices are shown located above and below the sensor 65.
  • Separate control line 63 can activate the sealing devices 64. It is preferable to create isolation zones that are as short as possible to minimize the volume of the zone, thereby minimizing any contamination that may pass through the barrier in device 66.
  • a small volume is further advantageous because it maximizes the fidelity of the dynamic response of the sensor 65.
  • Introducing sealing devices 64 further eliminates potential flow paths when multiple sensing zones are desired. For example, if the two sealing devices 64 that are shown between the two sensors 65 are removed, then a potential flow path is formed between the two pressure communication ports into the production string.
  • Figure 1 shows a schematic view of an oil or gas well, fitted with a control line for deploying and retrieving sensors and carrying out permanent downhole measurements, including the measurement of downhole pressure.
  • Figure 1 shows a production tubing string 11, surrounded by a casing string 12, a perforated section of the casing 13, to allow the inflow of hydrocarbon fluids 14 from the hydrocarbon reservoir into the well.
  • the well is completed by a wellhead 15 that includes valves 16 for shutting the well in.
  • a packer 17 is placed in the wellbore in the annular space formed between the casing 12 and the production tubing 11 to prevent the upper region of the annulus from being directly connected to the well bore pressure.
  • the packer 17 is shown with a high-pressure penetrator 18 that allows the hydraulic control lines 19 to pass through the packer.
  • the control lines are 0.635 cm (1 ⁇ 4 inch) in diameter and are made of stainless steel. It can be convenient to coil the control lines around the production string at one or more regions along that string.
  • the control lines can be secured to the production string by clamps 110, which also serve to protect the control lines from damage during installation.
  • the control line is shown exiting the wellhead through high pressure seals 111, past valves 112 which serve as emergency pressure seal and then through high pressure feed-through devices 113 where the fibre optic cables emerge while maintaining a pressure seal between the ambient surface environment and the interior of the control line.
  • the control line comprises optical fibre cables and sensors.
  • the sensors can include by way..of example only pressure sensors, distributed temperature sensors, acoustic sensors, electric and magnetic field sensors composition sensors and other types of sensors.
  • the sensors or their associated cables need not necessarily be fibre optic types..
  • the cable itself does not need to be connected to a sensor at all but can instead be used to communicate to an optical switch used to control downhole valves and machinery remotely. It is advantageous that the cables and sensors should be capable of being located to the remote locations by fluid flow, and thereby benefit from being retrievable and replaceable.
  • the control line is shown to reverse directions at a point 124 below the packer 17.
  • the return leg of the control line shown in Figure 1 includes a flow control element 115 located above the packer for example only.
  • This device 115 is configured to have two states, one of which can prevent flow of fluid in the upward direction or reduce flow to a reduced and acceptable rate. When the device is in the second state, fluid can flow freely in both directions.
  • a flow control element is used in both legs of the control line. Near the turn-around point 124, is shown a connection 116 to another section of control line that is shown to contain a flow control element 117 and which continues along the production string 11. Sensors that are deployed by use of the control line generally are prevented from entering the continuation of the control line beyond the turn-around region leading to the hydrocarbon reservoir.
  • a distributed temperature sensor such as can be used in conjunction with a distributed temperature sensing system, such as a DTS 80, available from York Sensors of Winchester, England, can be deployed in a single ended mode where the end of the sensor cable will be inside the control line, or in a double ended mode, where the sensor enters the control line in one leg and emerges at the surface from the other leg of the control line.
  • a distributed temperature sensing system such as a DTS 80, available from York Sensors of Winchester, England
  • DTS 80 distributed temperature sensing system
  • a typical polarimetric pressure sensor such as is available from Sensor Dynamics of Winchester, England, and its associated cable would enter the control line at the high pressure seal and the sensing part of the assembly would be located near the turn-around point of the control line, either in the down leg or in the up leg.
  • the well bore pressure at location 121 is communicated along the liquid pathway which starts at 121, connects to the barrier fluid reservoir at connection 123 and passes through the barrier fluids 125 and 122 inside the chamber 118, exits via connection 119 and continues through control line via connection 116 to the pressure transducer at location 114.
  • control line for deploying sensors is shown as a return control line, located in the annulus between the production string 11 and the casing 12, this should be regarded as one example only.
  • the assignee of the current invention has demonstrated in field trials examples of control lines which have been located both inside and outside the casing. In certain situations it can be preferable to locate the control line path inside the casing, in other situations it may be convenient or necessary to locate sensors outside the casing. For example, where acoustic information from the reservoir is assigned particularly high value, it is preferable to install the control line outside the casing. In another example, safety considerations can favour the location of the control line outside the casing in order to improve the isolation of the annular space above a packer from the zone below the packer.
  • the control line is preferably located inside the casing.-In yet other situations a mixture of both pathways may be preferred. For example, it is desirable to place the control line in the section above the packer outside the casing in order to have better acoustic coupling for reservoir imaging purposes while achieving a better isolation for safe operation, and yet to have the control line inside the casing for the purpose of monitoring the state of the perforated production interval.
  • the wall of the casing can be used for creating a control line path for the sensors and their cables. Equally, the control line path can make use of the interior of the production string 11 or the wall of the production string for all or part of the control line circuit.
  • control lines can make use of smallbore coiled tubing pathways or "lances" into the regions of the reservoir away from the production or injection wells. These coiled tubing lances can be used to collect a range of information including reservoir pressure, unaffected by the well bore effects, acoustic information, without high level interference from a producing well, composition information beyond the well' producing zone and others.
  • the flow control elements 115 and 117 that are shown in Figure 1 are not necessarily required when dealing with oil wells whose downhole pressure exceeds the pressure exerted by a control line that is entirely filled with a fluid.
  • the fluids 125 and 122 remain fully effective as a barrier between the highway fluid and the hydrocarbon reservoir fluid.
  • the use of the barrier fluid reservoir can also be eliminated or simplified. For example it can be replaced by a section of control line containing sufficient barrier fluid to compensate for expansion of the control line during a well shut-in.
  • control of fluid transfer to and from the control line via control elements 115 and 117 becomes important as does the barrier fluid reservoir 118.
  • a second example of the first embodiment of the present invention treats the case of the under-pressure well.
  • the operating downhole pressure well decreases; the height of fluid column that is sustained in the control line will also drop. It is to be expected that the downhole pressure during normal production will reach a point where the control line fluid will drop to a level below the uppermost point in the control line, leaving a section of control line that does not contain liquid.
  • the resulting transient in downhole pressure will tend to push fluid into the control line until the weight of the column balances the downhole pressure. It is preferable to minimise the amount of fluid that has to be transferred into the control line to equalise the pressure during a well shut down.
  • connections from point 121 into the barrier reservoir 118 and between 119 and the sensing location 114 are preferably as short as convenient and with a bore as large as is practical.
  • FIG. 2 we show by non-limiting example a configuration of the flow limiter (115 of Figure 1) that preferably includes a reservoir in the space above the sealing or choking element to minimise the change in level inside the control line during a negative pressure surge in the well bore due to imperfect sealing around the sensors or sensor cables inside the control line. That is, when the flow in the well is re-started following a period of shut-in, or when the well flow is simply increased, the pressure in the well bore will decrease and will eventually cause the level of liquid inside the control line to decrease.
  • control of the control line in accordance with the present invention can be achieved using only fluids of different density and viscosity downhole.
  • the main reasons for wanting to maintain control of the control line are (1) maximizing sensor performance and minimizing measurement uncertainty, (2) to control and elimination of outside fluids into the control line system, (3) elimination of any potential internal control line flow paths, (4) to permit the "clearing" of any minor segments of the control line system that may be come contaminated by outside matter over time and restore full sensor measurement quality, and (5) to facilitate the replacement of individual sensors in the case of multiple sensors in the same control line.
  • Figure 7 shows a schematic view of an oil or gas well, fitted with a control line for deploying and retrieving sensors and carrying out permanent downhole measurements, including the measurement of downhole pressure.
  • Figure 7 shows a production tubing string 79, surrounded by a casing string 77, and perforated section of the casing 710, to allow the inflow of reservoir fluids from the reservoir into the well.
  • the well is completed by a wellhead (not shown) that includes master shut-in valves (also not shown) for shutting the well in.
  • Packers 74 are installed to prevent the various regions of the annulus between the production tubing 79 and the casing 77 from being directly connected to the various reservoir zones.
  • the packers 74 are shown with high-pressure penetrators 75 which allow the hydraulic control lines 78, which constitute part of the control line to pass through the packer.
  • the control lines are 0.635 cm (1 ⁇ 4 inch) in diameter and are typically made of stainless steel.
  • the actual control lines for any specific well must be designed to meet or exceed the metallurgical requirements of the well completion design. It can be convenient to coil the control lines around the production string at one or more regions along that string.
  • the control lines can be secured to the production string by clamps 714, which also serve to protect the control lines from damage during installation.
  • the control line exits the wellhead through high pressure seals (not shown), past valves (also not shown) which serve as emergency pressure seals and then through high pressure feed-through devices (not shown), where the fibre optic cables emerge while maintaining a pressure seal between the ambient surface environment and the interior of the sensor highway system.
  • the control line system also includes "Y" branches 76, spur segments 72 to specific sensing locations, and connections to the inside of the production string 79 through the connecting port on the side pocket mandrel 73.
  • the control line system 700 contains optical fibre cables (not shown) and sensors (not shown).
  • the sensors can include by way of example only pressure sensors, distributed temperature sensors, acoustic sensors, electric and magnetic field sensors composition sensors and other types of sensors.
  • the sensors or their associated cables need not necessarily be fibre optic types.
  • the cable itself does not necessarily connect to a sensor at all but instead can be used to communicate to an optical switch used to control downhole valves and machinery remotely. It is most advantageous that the cables and/or sensors should be capable of being moved to the remote locations by fluid flow, and therefore benefit from being retrievable and replaceable. It is further intended that the fluid segmentation and sensor isolation within the control line be accomplished by timed fluid pumping to place the different fluids precisely where they are desired. The location of the fluid sections that provide isolation or segmentation functions can be determined by monitoring the volume of the propelling fluid. This is accomplished by utilizing the surface control line control valves in conjunction with the downhole flow control valves 716 located in the side pocket mandrels 73.
  • the flow control valves in different mandrels 73 are configured to change state at different flow rates and differential pressures.
  • the sensors or cables can be pumped into place to a position below where the gel plug 71 is intended to be set by manipulating flow rate in conjunction with the surface control valve (not shown) and the flow control valves 716 located in the side pocket mandrels 73.
  • Gel forming materials can be used. Hydrophilic organic polymers such as hydratable polysaxharides and hydratable synthetic polymers, e.g., polyacrylamide, can be used to form aqueous gels. Numerous solid metallic crosslinking or complexing agents can be employed to complex the hydrated gelling agents.
  • the metallic complexing agents can include antimony salts, aluminum salts, chromium salts, and certain organic titanates.
  • the exact placement of the sensor in control line segment 72 is typically dependent on the type of sensor used.
  • the fluid barriers 717 and the gel plug 71 can then be pumped into place by isolating the surface return line and controlling the flow path through either of the control line segments 72 via the flow control valves 716 located in the side pocket mandrels 73.
  • Barrier fluids and gel plug design preferably take into consideration the nature of the contaminates and reservoir fluids expected and the maximum differential pressure that may have to be maintained between the segment and the main body of the control line. Further isolation and segment protection can be achieved by placing "fiber friendly" valves (i.e., valves that can form a non-damaging seal around one or more fibers inside the control line) in the control line spur segments 72 above where the gel plugs 71 is placed.
  • An operational example can include a polarimetric pressure sensor available from SensorDynamics of Winchester, England.
  • the sensor and its attached fiber optic cable can enter the control line 700 at the high pressure seal at the wellhead.
  • the sensing part of the assembly can be located below the location of the control line "Y" 76 and below the location where the gel plug 71 is set within the control line segment 72.
  • the pressure is communicated to the sensor via a continuous fluid pathway that starts in the reservoir and enters the casing and production string and goes through the open downhole valve 716 in the side pocket mandrel 73 and connects to the barrier fluid in the control line segment 72 via the port 715.
  • the barrier plug 717 and the gel or segmenting plug 71 can be forced into the production string.
  • the cable and sensor can then be pumped back to the surface and a replacement sensor and cable can be re-installed along with a new barrier fluid 717 and a gel or segmenting plug 71.
  • FIG 2 describes a non-limiting example of the flow control element 115 of Figure 1. It should be clear that such flow control elements can be installed in one or both legs of the control line and also that the precise location along the control line can include locations above the packer as well as below the packer.
  • one or more fibre sensors or cables 21 are shown located inside the control line 22.
  • the control line continues into a container 23. Inside this container the control line is shown to be perforated so that fluid can readily enter the main volume of the container 23, while encouraging sensors and their cables to be guided along the control line.
  • Container 23 is shown to contain control line fluid 25 in the lower section of the container. Preferably this level is established by control from the surface, before flow from the well is re-established.
  • the purpose of the container is to reduce the change in fluid level in the control line for a given flow rate past the sealing or choking element and thereby minimise errors in the pressure measured at the sensing point. While the level of fluid is inside the volume 25, a small leakage past the seal or choke causes a much-reduced change in the column pressure.
  • the pressure at the sensing point in the well bore is at its highest when the well is stopped.
  • the control line fluid can be forced down to a level that is near the bottom of container 23 by using, for example pressurised nitrogen gas at the surface.
  • the seal or choke is then closed and the nitrogen gas pressure is released.
  • the use of the term choke in this context is meant to indicate a significant reduction in flow past the device.
  • the column of liquid in the control line will then be under positive pressure from the well bore. That is, if the choke element were to be opened, the well bore pressure would cause liquid to flow in the upward direction and reach a level above the choking element before the pressure exerted by the fluid column balances the well bore pressure.
  • the choke element For the purposes of monitoring the dynamics of the well bore pressure accurately it is preferable to have the choke element closed and where a fluid reservoir 23 is included, to have this reservoir at least partially filled with control line fluid.
  • the sensor reads the well bore pressure under these conditions. As flow is re-started in the well, the pressure in the well bore will drop, but it will remain greater than the pressure from the fluid in the control line provided the seal or choke is positioned low enough in the control line.
  • the control line 26 is shown to connect to the sealing or choking device 27 that contains a remotely controllable seal or choke 28 and to continue as section 210. Line 29 indicates remote control of the choke. Different methods can be used to effect control. One method is to have an independent hydraulic control line leading from the wellhead to sealing or choking device 27.
  • One such other method is to have a feed-forward connection from a point above the seal or choke to the control input 29. In this way the seal or choke can be set from the surface without an independent control line.
  • the arrangement shown in Figure 2 serves to minimise or reduce the amount of fluid which flows up the control line in the event of a positive pressure transient in the well bore and also to eliminate or reduce to an acceptable value the errors which can arise at the sensor in the event of a negative pressure surge in the well bore.
  • An alternative approach to the flow control device in Figure 2 is to eliminate the reservoir 24, but to retain the sealing device 27 and to make use of the barrier fluid reservoir 118 in Figure 1.
  • the sealing or choking elements are set closed. In the event of the well being shut in, the well bore pressure will increase. The sealing device 27 will prevent movement of fluid into the control line. After the positive pressure transient information has been acquired, the fluid in one leg of the control line can be expelled to the surface by application of over pressure nitrogen or another gas to one of the legs of the control line while opening the other entry point at the surface. The surface entry points are closed. The liquid will then settle to the lower sections of the two control line legs. At this time the seals or chokes 27 can be closed.
  • An alternative method that can be used to displace the deployment fluid inside the control line is to use another liquid that has the property that it changes to the gas phase at the well bore temperature. Under these conditions barrier fluid will be sucked upward into the control line if the control line is opened to ambient pressure at the wellhead. This method is preferred where it is desirable to surround the sensor and sensor cable by barrier fluid, in order to minimise degradation of sensors and cables in high temperature regions.
  • the gas in the region above the barrier fluid is preferably chosen to be an inert gas such as nitrogen, for example.
  • the gas in the control line above the seals is then allowed to come to ambient atmospheric pressure temporarily to allow the gas pressure to equilibrate approximately. At this stage the well bore pressure is at its highest and will be greater than the pressure exerted by the fluid column in the control line.
  • the maximum height h, of fluid of density p, between the choke and point of well production (32 in Figure 1), allowed so that the well pressure is greater than that due to the column of fluid can actually be quite small (of the order of a few hundred metres).
  • this level will depend very much on the density of the chosen control line fluid that could be significant if a liquid metal is used.
  • the deep positioning of the flow device will affect the operational specifications significantly as the temperature and pressure (in the early days of the well production) can both be extreme (temperatures up to 350°C in some steam flood wells). A deeply positioned flow device will also require a deep reaching additional hydraulic control line if this were to be the chosen method of flow device control.
  • an independent pressure sensor can be placed into the control line to sense the position of the liquid in the control line.
  • this pressure sensor is as far from the position 114 that is chosen to monitor the well bore pressure. The optimum point for this is immediately below the lowest equilibrium liquid level that can be expected during the life of the hydrocarbon reservoir. In an under-pressure well, this sensor will register the pressure due to the column of liquid above it. This information can be used to model the effect of fluid flow in the control line and to improve the data acquired by the primary pressure sensor which is located near the well bore at position 114 in Figure 1.
  • the device 117 which controls the flow of fluid between the barrier fluid reservoir and the control lines 19 in Figure 1 preferably include the following features: While the sensors are being deployed, the fluid flow from the control line into the barrier fluid reservoir is kept to a low rate so that the flow in both legs of the control line is sufficient to move the sensors and cables.
  • One solution which is given as a non-limiting example only, is to have a valve which allows downward flow from the control line up to a critical flow rate, at which time the valve closes to reduce or stop flow. This can be achieved by over-pressure from the surface at the start of any deployment operation.
  • the impedance for fluid transfer from the barrier fluid reservoir into the control line is preferably low in the region between the barrier fluid reservoir and the position of the pressure sensor, so that the pressure at the sensor is representative of the well bore pressure and does not become dominated by pressure drops between the pressure communicating point 121 and the sensor location 114. Choosing as large a bore for the fluid path as is practical reduces the impedance.
  • the flow control unit 117 is capable of replacement if it becomes sticky or damaged. One method for performing this is disclosed in US patent number 6,006,828, which is incorporated herein by reference in its entirety.
  • a barrier fluid assembly 300 is shown.
  • the control line that contains the pressure sensor 31 (and possibly other sensor) connects to a first barrier fluid reservoir section 320 at connection 33.
  • This reservoir is shown to contain a first barrier fluid 34 and a second barrier fluid 35.
  • the connection can contain a flow control device 32.
  • the first barrier fluid reservoir section 320 connects to a second barrier fluid reservoir section 330 at connector 38.
  • the second barrier fluid reservoir contains the second barrier fluid 35 and can also contain fluid 37 that is the same hydrocarbon fluid as the well bore fluid 37.
  • Barrier fluid 34 is of a lower density than barrier fluid 35 and the two fluids are preferably highly non-miscible.
  • Fluid 35 can be chosen to be a fluid such as an indium based alloy which is in the liquid state at the well bore temperature and which has a low propensity to react chemically with the hydrocarbon well bore fluids. Preferably fluid 35 also minimises the diffusion of molecular species of the well bore fluid. It should be recognised that a single barrier fluid can be sufficient in wells where the well bore fluid is sufficiently benign chemically. Equally it is possible to realise a design that includes a single reservoir container, even if two barrier fluids or more are used, provided that the relative densities are such that the ordering of fluids according to the densities achieves the objectives.
  • barrier fluid 34 or fluid 35 become contaminated or degraded, then it is possible to displace these into the well bore and replace the fluids with new fluids without requiring the well to be shut in. This can be achieved for example, by injecting fluids 34 or 35 at the wellhead through the hydraulic control line. If the ambient well surface temperature is below the melting points of either fluids, then these materials can be injected in the form of small pellets. These pellets will change to liquid at a depth where the well temperature exceeds the melting point of the pellet material.
  • Barrier fluid 34 is preferably a liquid metal such as gallium or other metal which is in the liquid state at the well bore temperature, which is of lower density than fluid 35 and which does not tend to mix with fluid 35.
  • This fluid 34 can also be a non-metallic fluid that is inert with respect to fluid 35 and with respect to the pressure sensor or its package.
  • the first barrier fluid 34 is also preferably chosen to have a low viscosity so that it can flow with low resistance within the control line 31 and thereby minimise errors in the measurements by the pressure sensor due to flow induced pressure gradients between pressure communication point 31 and the position of the pressure sensor.
  • a multiple barrier fluid configuration of figure 3 can also be achieved with an annular vessel similar to that shown in the separate plan view detail in Figure 1.
  • the choice of either configuration depends upon ease of fabrication and incorporation into a particular well.
  • Figure 4 we show the control line 41 containing one or more sensors connected into a barrier fluid reservoir 43 via a section of control line that can include a flow control device 42.
  • the hydrocarbon reservoir fluid 45 is allowed direct access to the interior of the barrier fluid reservoir at point 46 and can enter the chamber 43.
  • fluid 44 that acts as a fluid barrier between well bore fluid 45 and the sensor and its package. It is to be realised that a further fluid can be in the control line in the region where the sensor is located or above it
  • a mechanical piston 47 is shown separating the fluids 44 and 45. This piston can contain a small-bore connection 48 which can be filled with fluid 44.
  • the piston assembly communicates the pressure of the well bore to the interior of the control line.
  • the mechanical piston can be designed so that it can be replaced by wireline or slickline intervention or by use of a robotic vehicle.
  • FIG. 5 shows a non-limiting example of an apparatus that provides a mechanical isolation or separation of reservoir fluids from control line fluids.
  • a membrane or diaphragm 52 is shown in an annular space 50 surrounding a production string 51.
  • the membrane or diaphragm divides the annular space into two regions.
  • On one side of the membrane is a space that contains a fluid 54.
  • On the other side of the membrane is a space containing fluid 55.
  • Fluid 55 is reservoir fluid also shown as 56.
  • the reservoir fluid 56 can enter the adjacent annular space at one or more ports 53.
  • the fluid 54 can be the same fluid as is used in the control line 57 that is connected to the outer annular space at port 59. If the pressure inside the production string changes then this change in pressure is communicated to the fluid inside the control line.
  • the membrane adjusts its position in response to pressure changes. It is important to adjust the initial position of the membrane or diaphragm by applying pressure to the control line at the surface.
  • the preferred static position of the membrane when the well is shut in and where the well bore pressure is therefore at its highest should be near the outer wall of the annular space. When the well is flowing at its maximum rate, the well bore pressure will generally be at it lowest. Going from well shut-in to well flowing can cause fluid transfer from the highway into the annular surge chamber.
  • the size of the overall annular space is chosen to be sufficient for the particular well conditions. Where large changes in pressure are forecast, the length of the annular surge chamber has to be greater than in wells where relatively small changes are expected.
  • flow restrictors 510 are built into the control line above the position of the pressure sensor then the size of the chamber necessary is reduced. In general the preferred position of the pressure sensor inside the control line is near the connection to the annular surge chamber (shown as 511 in figure 5).

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  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geophysics (AREA)
  • Measuring Fluid Pressure (AREA)
  • Measuring Pulse, Heart Rate, Blood Pressure Or Blood Flow (AREA)
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  • Measurement Of Velocity Or Position Using Acoustic Or Ultrasonic Waves (AREA)
  • Cable Accessories (AREA)

Claims (16)

  1. Gerät zum Erfassen ein oder mehrerer physikalischer Parameter an einem entfernten Ort, umfassend
    eine erste Steuerleitung (19, 22, 57, 62, 68), enthaltend ein Kommunikationskabel und einen Sensor in Kommunikation damit, wobei der Sensor (31, 65) sich befindet in der ersten Steuerleitung (14, 22, 52, 62, 78) in der Nähe des entfernten Ort;
    eine zweite Steuerleitung mit einem ersten Ende (116) in Fluidverbindung mit der ersten Steuerleitung (19, 22, 57, 62, 68) in der Nähe des Sensors (31, 65) und einem zweiten Ende (119); und
    eine Fluidsperrenreservoir (118, 23, 320, 330, 43), enthaltend eine Sperrflüssigkeit (122, 34, 212), wobei die Fluidsperre eine erste Öffnung besitzt in Fluidverbindung mit dem zweiten Ende (119) der zweiten Steuerleitung und eine zweite Öffnung (123) in Fluidverbindung mit dem entfernten Ort.
  2. Gerät nach Anspruch 1, zudem umfassend ein erstes Flussregelelement, angeordnet in der zweiten Steuerleitung zwischen der ersten Steuerleitung und dem Fluidsperrenreservoir, wobei das erste Flussregelelement ausgelegt ist für eine Schaltung zwischen einem ersten Zustand, in dem es einen Fluidfluss in der zweiten Steuerleitung in jeder Richtung erlaubt, und einem zweiten Zustand, in dem es in der zweiten Steuerleitung den Fluidfluss vom Fluidsperrenreservoir zur ersten Steuerleitung begrenzt.
  3. Gerät nach Anspruch 2, zudem umfassend ein zweites Flussregelelement, angeordnet in der ersten Steuerleitung, wobei das zweite Flussregelelement ausgelegt ist für ein Schalten zwischen einem ersten Zustand, in dem es einen Fluidfluss in der ersten Steuerleitung in jeder Richtung erlaubt, und einem zweiten Zustand, in dem es einen Fluidfluss aus der ersten Steuerleitung begrenzt.
  4. Gerät nach Anspruch 1, zudem umfassend einen Gelstopfen, angeordnet in der zweiten Steuerleitung zwischen der ersten Steuerleitung und dem Sperrfluidreservoir, wobei der Gelstopfen ein Gelvolumen einnimmt, das für eine chemische Trennung des Sperrfluids von den Fluiden in der Steuerleitung sorgt.
  5. Gerät nach Anspruch 4, zudem umfassend ein Rohr mit einem ersten Ende in Fluidverbindung mit dem Sperrfluidreservoir und einem zweiten Ende in Fluidverbindung mit dem entfernten Ort und zudem umfassend ein fluidbetätigtes Regelventil, das in dem Rohr angeordnet ist, wobei das fluidbetätigte Regelventil reagiert, dass es offen ist, wenn Fluid durch das Rohr und die erste und die zweite Steuerleitung gepumpt wird.
  6. Gerät nach Anspruch 1, zudem umfassend eine Fluidvortriebeinrichtung zum Leiten von Fluid in die erste und die zweite Steuerleitung sowie eine Fluidvolumen-Messvorrichtung, ausgelegt zum Messen des Fluidvolumens, das von der Fluidvortriebeinrichtung in die erste und die zweite Steuerleitung geschickt wird.
  7. Gerät nach Anspruch 1 zum Erfühlen ein oder mehrerer physikalischer Parameter an entfernten Orten, umfassend
    eine Anzahl Sensoren in Verbindung mit dem Kommunikationskabel, wobei jeder Sensor angeordnet ist innerhalb der ersten Steuerleitung in der Nähe des jeweils entfernten Orts; und
    eine Anzahl Fluidsperren-Sensorabschnitte, wobei jeder Fluidsperren-Sensorabschnitt umfasst
    eine zweite Steuerleitung mit einem ersten Ende in Fluidverbindung mit der ersten Steuerleitung in der Nähe einer der Sensoren und ein zweites Ende; und
    ein Fluidsperrenreservoir, enthaltend ein Sperrfluid, wobei die Fluidsperre eine erste Öffnung besitzt in Fluidverbindung mit dem zweiten Ende der zugehörigen zweiten Steuerleitung und eine zweite Öffnung in Fluidverbindung mit dem zugehörigen entfernten Ort.
  8. Gerät nach Anspruch 1, wobei das Kommunikationskabel ein optisches Faserkabel ist.
  9. Fluidsperre zum Isolieren eines Sensors (31, 65), der in der ersten Steuerleitung (19, 22, 57, 62, 68) enthalten ist von einer Umgebung (122, 34, 212) an einem Ort in der Nähe des Sensors (31, 65), umfassend
    eine Fluiddurchleitung mit einem ersten Ende (116) in Fluidverbindung mit der ersten Steuerleitung (19, 22, 57, 62, 78) in der Nähe des Sensors (31, 65) und einem zweiten Ende (119); und
    ein erstes Fluidsperrenreservoir (118, 23, 320, 330, 43) mit einer ersten Öffnung in Fluidverbindung mit dem entfernten Ort und eine zweite Öffnung in Fluidverbindung mit dem zweiten Ende der Fluiddurchleitung (119), wobei die erste Öffnung zur zweiten Öffnung distal entfernt ist und das erste Fluidsperrenreservoir (118, 23, 320, 330, 43) ein erstes Fluid enthält mit einer ersten spezifischen Dichte.
  10. Fluidsperre nach Anspruch 9, zudem umfassend ein zweites Fluidsperrenreservoir, das angeordnet ist in der Fluiddurchleitung zwischen dem ersten Fluidsperrenreservoir und der ersten Steuerleitung, wobei das zweite Fluidreservoir eine erste und eine zweite Öffnung besitzt für den Anschluss an die Fluiddurchleitung, die erste Öffnung distal entfernt ist zur zweiten Öffnung, das zweite Fluidsperrenreservoir ein zweites Fluid enthält mit einer zweiten spezifischen Dichte, die anders ist als die erste spezifische Dichte.
  11. Fluidsperre nach Anspruch 10, wobei das zweite Fluidsperrenreservoir höher angeordnet ist als das erste Fluidsperrenreservoir und die erste spezifische Dichte größer ist als die zweite spezifische Dichte.
  12. Fluidsperre nach Anspruch 11, zudem umfassend ein fluidbetätigtes Regelventil, das in der Fluiddurchleitung angeordnet ist zwischen dem zweiten Fluidsperrenreservoir und der ersten Steuerleitung, das fluidbetätigte Regelventil so reagiert, dass es offen ist, wenn Fluid durch die Fluiddurchleitung zum zweiten und zum ersten Fluidsperrenreservoir gepumpt wird.
  13. Fluidsperre nach Anspruch 10, wobei das erste und das zweite Fluid im Wesentlichen miteinander unmischbar sind und zudem das erste Fluid ausgewählt ist aus im Wesentlichen zur Umgebung am entfernten Ort chemisch inerten Stoffen.
  14. Verfahren zum chemischen Isolieren eines Sensors (31, 65) von einem Ort, an dem ein Parameter vom Sensor (31, 65) zu messen ist und der in einer fluiden Umgebung ist, umfassend
    Einrichten innerhalb einer Steuerleitung (19, 22, 57, 62, 68) eines Sensors in Signalkommunikation mit einem Kommunikationskabel (21), wobei der Sensor (31, 65) sich in einem Abschnitt der Steuerleitung (19, 22, 57, 62, 78) in der Nähe des Orts, an dem der Parameter zu messen ist, befindet;
    Stellen in dem Abschnitt der Steuerleitung (19, 22, 57, 62, 78), der den Sensor (31, 65) enthält, eines Fluidreservoirs (118, 23, 320, 330, 43) in Fluidverbindung, wobei das Fluidreservoir (118, 23, 320, 330, 43) zudem in Fluidverbindung steht mit der Fluidumgebung;
    Isolieren der Steuerleitung (19, 22, 57, 62, 78), um einen Durchfluss des Fluids in die Steuerleitung (19, 22, 57, 62, 78) aus der Fluidumgebung zu verhindern und
    Leiten eines ersten Fluids in die Steuerleitung (19, 22, 57, 62, 78), so dass das erste Fluid in das Fluidreservoir (118, 23, 320, 330, 43) fließt.
  15. Verfahren nach Anspruch 14, zudem umfassend das Messen des Volumens des ersten Fluids, das die Steuerleitung hinunter in das Reservoir fließt und Beenden des Flusses des ersten Fluids in die Steuerleitung, wenn genügend Volumen an erstem Fluid in die Steuerleitung hinunter geflossen ist, so dass mindestens ein Teil des Fluidreservoirs gefüllt ist.
  16. Verfahren nach Anspruch 14, zudem umfassend das Herstellen einer Durchfluss-Fluidverbindung mit dem Abschnitt der Steuerleitung, die den Sensor und das Fluidreservoir eines zweiten Fluidreservoirs enthält und Leiten eines zweiten Fluids in die Steuerleitung, so dass das zweite Fluid in das zweite Fluidreservoir hinunter fließt.
EP00907123A 1999-02-05 2000-02-02 Vorrichtung und verfahren zur erhöhung der leistung eines fernsensors Expired - Lifetime EP1070196B1 (de)

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GBGB9902596.7A GB9902596D0 (en) 1999-02-05 1999-02-05 Apparatus and method for protecting sensors and cables in hostile environments
GB9902596 1999-02-05
PCT/US2000/002748 WO2000046485A2 (en) 1999-02-05 2000-02-02 Apparatus and method for enhancing remote sensor performance

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WO2005035943A1 (en) * 2003-10-10 2005-04-21 Schlumberger Surenco Sa System and method for determining flow rates in a well
CA2509928C (en) 2004-06-17 2009-01-27 Schlumberger Canada Limited Apparatus and method to detect actuation of a flow control device
WO2006079154A1 (en) * 2004-10-22 2006-08-03 Geomole Pty Ltd Method and apparatus for sensor deployment
US7673679B2 (en) * 2005-09-19 2010-03-09 Schlumberger Technology Corporation Protective barriers for small devices

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GB9209434D0 (en) * 1992-05-01 1992-06-17 Sensor Dynamics Ltd Remotely deployable pressure sensor
GB9324334D0 (en) * 1993-11-26 1994-01-12 Sensor Dynamics Ltd Apparatus for the remote measurement of physical parameters
US5503013A (en) * 1994-08-01 1996-04-02 Halliburton Company Downhole memory gauge protection system
GB9419006D0 (en) * 1994-09-21 1994-11-09 Sensor Dynamics Ltd Apparatus for sensor installation
GB9519880D0 (en) * 1995-09-29 1995-11-29 Sensor Dynamics Ltd Apparatus for measuring pressure
NO954659D0 (no) * 1995-11-17 1995-11-17 Smedvig Technology As Måleutstyr for brönn
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EP1070196A1 (de) 2001-01-24
WO2000046485A3 (en) 2000-11-30
ATE328189T1 (de) 2006-06-15
CA2326900C (en) 2008-04-22
NO325276B1 (no) 2008-03-17
WO2000046485A2 (en) 2000-08-10
GB9902596D0 (en) 1999-03-24

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