NO325276B1 - Apparatus and method for isolating a sensor from an environment in a borehole - Google Patents

Description

The present invention relates to remote sensing devices, and in particular to fiber optic sensors and communication cables used in such sensing devices, more particularly to methods and devices for protecting such sensors, communication cables and wires containing such sensors and communication cables, against damage as a result of the surrounding environment at the remote location.

Sensors for measuring pressure, temperature and temperature profiles, acoustic pressure waves and vibrations, magnetic fields, electric fields and chemical compositions can potentially produce valuable information that can be used to characterize oil and gas reservoirs and to manage cost-effective and safe extraction of hydrocarbon reserves from oil and gas wells. Placement of such sensors in suitable positions in oil and gas wells using conventional methods is difficult and expensive. It is common practice in the oil industry to use cables or smooth wires to lower sensors into remote positions down the borehole. While this type of deployment provides valuable information, the procedures make use of expensive equipment and personnel, and require normal production to be interrupted. Smooth wire and wire procedures also produce only random information.

Alternatively, it is possible to place sensors downhole permanently, but the conventional methods of doing this make use of specialized cables permanently attached to the production string, and complicated mechanical packages such as side pocket mandrels. This method of installing permanent sensors is extremely expensive and high failure rates are common. When a fault occurs, it is not possible to correct it without extensive and extremely expensive intervention. In general, this is considered impractical. Repairs can then only be carried out when a well must be overhauled for other compelling reasons. Even under such conditions, the correction of the error is costly. It is common experience that conventional pressure sensors, such as quartz gauges and silicon strain gauges, fail after relatively short periods under high wellbore temperatures and pressures. E.g. at 135 °C or higher, the expected lifetime is short. Reasons for failure are often difficult or impossible to determine, but contributions to failure include failure of the transducer itself, or the electronics in the borehole, degradation of cables and contamination of connectors.

These well-known shortcomings of conventional sensors have led to the development of new types of sensors that can make use of fiber optic technology. The benefits that are always expected from this technology include the elimination of downhole electronics.

EP 0 774 565 A2 describes a device comprising monitoring instruments which are carried by a pipe which is suspended in a hanger which is suspended in a production pipe. Signals from the monitoring instruments are transmitted to the surface using an instrument cable that runs along the pipe, through the hanger and along the production pipe.

GB 2 305 724 A describes an optical pressure gauge which is pumped with fluid through a pipeline to a remote location in a borehole where pressure is measured. A flow barrier, such as a valve, diaphragm, or baffle, restricts fluid from the measuring point from flowing into the pipeline.

US 5,570,437 and US 5,582,064 describe methods and devices for deploying sensors in remote areas of oil wells, which can provide permanent monitoring and yet allow cost-effective corrections should the sensors or their associated cables fail. These techniques make use of hydraulic control lines as a "highway" to deliver the sensors to the remote locations. The hydraulic control lines are robust and provide effective protection for the sensors and their cables against damage during installation. Until now, the only sensors that have been able to use this type of deployment have been fiber optic sensors. They can be extremely small and flexible, and can benefit from equally small and flexible cables. This allows such sensors to be guided along small diameter hydraulic control lines by fluid resistance, and to be placed in remote locations in oil and gas wells. Water is the most suitable fluid for deploying such fiber optic sensors in hydraulic control lines, as it is readily available, has an extremely low viscosity for pumping, and can withstand conditions of very high temperatures at high pressures. Extensive laboratory testing of the assignatar for the present invention has, however, demonstrated that when fiber optic sensors or fiber optic cables are exposed to water at a higher temperature than 70 °C and at the same time too high pressure, e.g. 140 kg/cm<2>, the water will cause damage to the sensor and also to the cables. It has been shown that water in direct contact with silicon oxide fibers can enter and react with silicon oxide to create highly charged layers inside the optical fibers. This can also cause defects on the silicon oxide through etching. In fiber optic pressure sensors, water ingress has been directly associated with rapid drift in the zero point of fiber optic pressure sensors. At 150 °C or higher, the zero point for unprotected fiber optic pressure sensors can change by more than 280 kg/cm<2> over relatively short periods of time. Similar extreme behavior has been shown to occur when unprotected fiber optic Bragg gratings are exposed to water under these conditions. Optical fibers have also been shown to change dramatically in length as a result of conditions inside the wellbore. Changes of more than 1% have been measured.

In an attempt to circumvent these undesirable effects, water has been replaced with a number of other fluids, including silicone or perfluorocarbon fluids and others, some of which are generally considered to be very inert and stable, even at temperatures above 200°C. Experiments with these fluids showed that damage rates could be reduced, but none of the fluids could eliminate damage in its entirety.

Similar samples with coated fibers show some improvements, but in no case could a coating or combination of coatings be found that promised long-term survival of optical cables, or that reduced the zero point instability of fiber optic pressure sensors to acceptable levels. Significant improvements were found when optical fibers were coated with carbon, preferably followed by polyimide. However, even the most promising improvements were insufficient to provide a commercially attractive solution. A particular limitation that was identified appears to be associated with pinholes in the coatings, which are very difficult to detect and act as centers of chemical attack that can lead to widespread damage.

This has led to a widespread search for other coatings that can be applied to the fiber optic sensors and to cables to prevent attack by water or other molecules. Extensive laboratory testing of the assignatar of the present invention showed that a wide range of metal coatings could not protect sensors or cables when exposed to water at high temperatures. Copper, gold and other metals were tried. None survived tests at 250 °C in water, over a long period of time. All coatings were found to affect the temperature sensitivity of the pressure sensor in an undesirable manner, increasing the unwanted temperature sensitivity of a pressure sensor by more than one order of magnitude. In each case, additional complications were anticipated in protective fusion splices that inevitably expose silicon oxide to the environment where optical fibers are joined.

It has been demonstrated that fiber optic sensors can be effectively protected to provide stable response at high temperatures and pressures when the sensors are surrounded by silicone oil. This protection can be extended so that the sensors can be deployed in remote locations, including downholes in oil and gas wells, where the wellbore fluids can be very corrosive.

A patent application from SensorDynamics, GB 9827735.3, shows the use of liquid metals or other liquids in conjunction with a silicon oxide or elastomer capillary. Other materials can also be chosen for the capillary, e.g. sapphire. The use of metals or other materials which are in a liquid state under the expected operating conditions introduces a number of desirable features. Many liquid metals will readily "wet", thus forming a tight interface with silicon oxide. Some liquid metals, e.g. indium, has been reported to bind to silicon oxide. This also makes it possible to form a highly reflective surface at a fiber-cleaved end face when it is "wetted" by a liquid metal or where the liquid metal bonds to the silicon oxide surface. Liquids cannot support shear stress, and therefore will not cause sensors to change their behavior with changing temperature. For example, polarimetric pressure sensors will not become very sensitive to changes in temperature. Liquid metals can also easily protect splice areas as well as coated areas of optical fibers and mirrors. Liquid metals can be applied relatively easily to fibers and pumped into capillaries. The use of liquid interfaces between sensor surfaces and the surrounding capillary will further allow the use of multiple coatings on the inner and outer surfaces of the capillary without introducing temperature sensitivity effects into the sensor. In principle, the capillary can be used to increase the protection in cables as well as sensors.

When pressure sensors are placed inside hydraulic control lines, called "sensor main roads", it is necessary to ensure that the pressure down in the well holes can be transferred to the interior of the sensor main road where the sensors are located.

The interior of the sensor main path may be filled with a fluid. The fluid can be in the form of liquid or gas. A usable fluid is an inert oil, such as silicone-based oil, which can be relatively stable at normal borehole temperatures and pressures. Silicone-based fluids stable at 250 °C and above can be obtained commercially. The stability of these fluids varies depending on their purity. It can be difficult to guarantee the purity of such fluids over long periods if the fluids are not enclosed in a hermetically sealed environment. When the highway fluids are allowed to be in direct contact with the wellbore fluids, diffusion and convection can occur. This can result in the ingress of water molecules and other substances into the main pathway. Over time, this can result in an unfriendly environment that attacks even carefully packaged sensors.

It is therefore of great value to devise means to establish and maintain the fluid surrounding the sensors and cables in a state that minimizes changes in the sensors and cables.

The present invention describes methods and devices for creating barriers and segments in a sensor highway using fluids or mechanical devices, for any and all of the following purposes: 1. Countering or preventing the penetration of external fluids or reservoir fluids into the highway (communication /barrier function), 2. Segmentation of the main path to form separate sensor areas (the segmentation function).

3. Maximizing the long-term performance of sensors in the main road.

According to the invention, a device is provided for isolating a sensor from an environment at a remote location in a borehole where the sensor senses one or more physical parameters, which device is characterized by the features indicated in the characterizing part of claim 1.

According to the invention, a fluid barrier is also provided to isolate a sensor that is placed inside a first control line, from an environment at a location close to the sensor, where the fluid barrier is characterized by the features indicated in the characterizing part of claim 9.

According to the invention, there is also provided a method for chemically isolating a sensor from a location where a parameter is to be measured by the sensor, the location being in a fluid environment in a borehole, which method is characterized by the features indicated in the characterizing part of claim 14.

The invention includes devices and methods for sensing one or more physical parameters at a remote location and at the same time minimizing or eliminating contact between reservoir fluids and the like at the remote location, and the sensor used to sense the physical parameters. In one embodiment, the device isolates the sensor inside a tube containing the sensor. In particular, the device comprises a pipe containing a communication cable and a sensor in communication with the cable, the sensor being placed inside the pipe near the remote location. A sealing device is designed to seal a section of the tube containing the sensor from fluid flow within the tube, the sealing device being designed to be activated between a sealing state and a non-sealing state. The device further comprises a communication device in fluid connection with the remote location and the pipe section containing the sensor. A control line is in connection with the sealing device and is designed to activate the sealing device between the sealing state and the non-sealing state. In a second embodiment, the device is designed to form a barrier of a fluid between the sensor and the environment at the remote location. In particular, the latter device comprises a first pipe containing a communication cable and a sensor in communication with the cable, the sensor being placed inside the pipe near the remote location. The device further comprises a second pipe which has a first end in fluid connection with the first pipe near the sensor. A fluid barrier reservoir containing a barrier fluid is also arranged, where the fluid barrier has a first opening in fluid connection with a second end of the second pipe, and a second opening in fluid connection with the remote location.

In the following, the invention will be described in more detail with reference to the drawings, where

figure IA shows a schematic side view of a borehole containing a sensing device according to one embodiment of the invention,

figure IB shows a cross-section of the device in figure IA along the line IB-IB,

figure 2 shows a schematic view of an example of a flow restrictor that can be used in the sensing device of figure 1,

figure 3 shows a schematic view of a first barrier fluid unit that can be used in the sensing device according to the invention,

figure 4 shows a schematic diagram of a second barrier fluid unit that can be used in the sensing device according to the invention,

figure 5 shows a schematic view of a device which produces a mechanical isolation or separation of reservoir fluids from highway fluids,

Figure 6 shows a schematic side view of a borehole containing a sensing device according to a second embodiment of the invention, and

Figure 7 shows a detailed schematic diagram of a sensing device inside a borehole according to a third embodiment of the invention.

When obtaining pressure information in a borehole, the pressure connection from the borehole to the sensor inside the main road should preferably be such that little water or borehole fluid can enter the main road. It is important to minimize the possibility of foreign molecules entering the sensor and thereby causing drift. Water molecules and OH groups are known to be chemically very aggressive at high temperatures and pressures, and borehole fluids vary widely in composition, from well to well and over time. These fluids can be chemically extremely aggressive.

A method according to prior art that reduces or eliminates penetration of molecules from well holes into the area where the sensor is placed is to insert a membrane. This method brings with it a number of disadvantages that can lead to difficulties in obtaining pressure information accurately. E.g. the membrane must respond to very small changes in pressure, and the direct contact with the wellbore fluids can result in corrosion or scaling that changes the response of the membrane to pressure changes. It is also difficult to create a mechanical device that can have the dynamic range that is necessary to cover the large pressure increases or that can dissolve the small pressure changes that can occur in oil and gas wells.

According to a first embodiment of the present invention, an alternative approach to reduce or eliminate penetration of molecules from the wellbore into the area where the sensor is located is to allow a direct connection between the wellbore fluid and the interior of the sensor pathway, in such a way that the wellbore fluid is prevented as much as possible from causing unwanted changes in the sensors or cables and at the same time allowing relevant information to be obtained by the sensors.

In one example of the first embodiment of the invention, the wellbore pressure can be accurately communicated to the sensor through one or more intermediate fluids. The intermediate liquids are chosen so that long-term exposure results in minimal changes in the sensor. It is also preferable that the intermediate fluids can be easily replaced if contamination or degradation occurs in particularly unfriendly environments. Preferably, this does not require the removal of the sensors and cables in the main path.

In another example of the first embodiment of the invention, when the composition of the wellbore fluid is to be analyzed, the composition sensor probe is in direct contact with the wellbore fluid. It is preferable that direct contact between the wellbore fluid and the sensor probe is limited to the time when the measurement takes place and that the sensor probe is otherwise in an environment that does not change or degrade the sensor or the cable. For example, when a fiberoptic fluorescence probe is used to determine aspects of the chemical composition of the wellbore fluid, the end of the fiberoptic probe should be directly immersed in the wellbore fluid. If this direct contact is maintained permanently, it is likely that the optical fiber will suffer damage. On the other hand, the useful life of the probe is extended if direct contact is only incidental and if an inert fluid surrounds the probe at all other times. Two examples will be described of how sensors and cables can be protected from damage when the sensors are used in oil wells. The examples are intended to be non-limiting. One example deals with the case of an overpressured well, while the other deals with the case of an underpressured well.

An overpressured well has a wellbore pressure that is higher than the pressure exerted by a main road that is completely filled with fluid. That is, if the main road were to be opened to atmospheric pressure at the wellhead, the fluid would be forced to flow upwards through the main road. When the main road is blocked at the upper end of the main road, the fluid at the top point will be at a positive pressure. This overpressure condition typically applies to oil wells during their early production phases where the hydrocarbon reservoir pressure is at its highest. If the fluid inside the main path is a fluid that has been carefully degassed, this column of fluid has a high bulk modulus, and therefore compresses very little under hydrostatic pressure. Under these conditions, an increase in the pressure down the borehole, which can occur when the amount of flow in the well decreases or is shut off, will not cause any significant amounts of wellbore fluid to enter the main road.

In this case, pressure from the wellbore can be communicated simply to the sensor inside the main road using a length of pipe connecting the wellbore to the main road. This tube can be filled with (one or more) liquid metals or other fluids whose composition is such that it causes the least possible change in the sensor over a long period of time. Alternatively, a combination of fluids may be selected to form the barrier. The liquid metal or other fluid should preferably not mix easily or react chemically with the constituents of the wellbore fluid. The function of this liquid metal or other liquid is to form a barrier against molecules from the wellbore fluid and to prevent these from entering the main path and reaching the sensor.

The pressure communication pipe which enables direct pressure communication between the hydrocarbon reservoir fluid and the main road fluid should preferably be arranged so that the wellbore fluid comes into contact with the liquid metal from above to prevent gas rising from the wellbore, through the column of liquid metal or other fluid or series of fluids. This can be achieved by shaping the connecting pipe into an elbow, with the wellbore end of the column pointing upwards.

The present invention thus includes methods and devices for creating barriers and segments in a sensor highway by using fluids or mechanical devices for any or all of the following purposes: 1. To counteract or prevent the penetration of external fluids or reservoir fluids into the highway (the communication/barrier function), 2. Segmentation of the main pathway to form separate sensor areas (the segmentation function), and

3. Maximizing the long-term performance of sensors in the highway.

Figure 6 schematically illustrates an example of how these goals can be achieved, with particular reference to measurements of pressure at more than one point in a main sensor pathway. A section of an oil or gas well is shown, comprising a casing 67, a production string 60, a packing 61. The packing separates the annulus between the casing and the production string into two areas - a section above the packing and another section below the packing. A sensor main path 62 and a separate hydraulic control line 63 are shown in the annulus between the casing and the production pipe, and both penetrate the packing. The main sensor path 62 is shown as a continuous control line which reverses at a point below the gasket 61. In this drawing, two devices are also shown for measuring pressure at a point above the gasket 61 and another point below the gasket. Each device comprises sealing devices 64, a pressure sensor 65 and a pressure communication device 66. The pressure communication device 66 preferably comprises a facility which allows it to be closed and opened from the surface. The pressure communication device 66 is connected to the wellbore fluids inside the production string 60, and may preferably comprise a barrier function that prevents or minimizes the penetration of wellbore fluids into the main path area between the two sealing devices 64. The sealing devices are shown positioned above and below the sensor 65. The separate control line 63 can activate the sealing devices 64. It is preferred to create isolation zones that are as short as possible to minimize the volume of the zone, thereby minimizing contamination that can pass through the barrier in the device 66. A small volume is also advantageous because it maximizes the accuracy of the dynamic response of the sensor 65. Introduction of sealing devices 64 further eliminates potential flow paths when multiple sensor zones are desired. For example, if the two sealing devices 64 shown between the two sensors 65 are removed, a potential flow path is formed between the two try communication ports into the production string.

Figure 1 shows a schematic view of an oil or gas well, equipped with a main road 100 for deploying and retrieving sensors and for carrying out permanent measurements down the borehole, including measurements of pressure in the borehole. Figure 1 shows a production tubing string 11, surrounded by a casing string 12, and a perforated section of the casing 13, to allow inflow of hydrocarbon fluids 14 from the hydrocarbon reservoir into the well. The well is completed with a wellhead 15 which includes valves 16 to close the well. A gasket 17 is placed in the borehole in the annulus formed between the casing 12 and the production pipe 11 to prevent the upper area of the annulus from being directly connected to the borehole pressure. The gasket 17 is shown with a high pressure penetrator 18 which allows the hydraulic control lines 19, which form part of the sensor main path 100, to pass through the gasket. Typically, the control wires are 1/4 inch in diameter and made of stainless steel. It may be appropriate to wrap the control wires around the production string in one or more areas along the string. The control wires can be attached to the production string with clamps 110, which also serve to protect the control wires from damage during installation. The sensor main path 100 is shown to exit the wellhead through high pressure seals 111, past valves 112 which serve as an emergency pressure seal and then through high pressure feed-through devices 113 where the fiber optic cables exit while maintaining a pressure seal between the surrounding surface environment and the interior of the sensor main path. The sensor highway 100 comprises fiber optic cables and sensors. The sensors can include e.g. 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 do not necessarily have to be fiber optic types. The cable itself does not need to be connected to a sensor at all, but can instead be used to communicate with an optical switch used to remotely control valves and machinery downhole. It is advantageous that the cables and sensors should be able to be placed in the remote locations by fluid flow, and thus benefit from the fact that they can be retrieved and replaced. In figure 1, it is shown that the main sensor path 100 reverses directions at a point 124 below the gasket 17. The return section of the main path shown in figure 1 comprises a flow control element 115 which is placed e.g. just above the gasket. This device 115 is designed to have two states, one of which can prevent the flow of fluid in an upward direction or reduce the flow to a reduced and acceptable amount. When the device is in the second state, fluid can flow freely in both directions. A flow control element is preferably used in both sections of the main road. Near the turning point 124 is shown a connection 116 to another section of the control line which is shown to contain a flow control element 117 and which continues along the production string 11. Sensors deployed using the main road are generally prevented from entering the continuation of the control line past the turning point area as leading to the hydrocarbon reservoir. A distributed temperature sensor, e.g. one that 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 trunk 100, or in a double-ended mode, where the sensor enters the main road in one section and exits at the surface from the other section of the main road. In general, other sensors, such as pressure, acoustic, electric field and composition sensors, may operate in reflection mode and thus enter the downward stretch of the highway during deployment, but only emerge from the other end of the highway when they need to be retrieved from the highway. For example, a typical polarimetric pressure sensor, e.g. one available from SensorDynamics of Winchester, England, and its associated cable would enter the trunk at the high-pressure seal, and the sensing portion of the assembly would be located near the turning point of the trunk, either on the down or up stretch. The wellbore pressure at location 121 is communicated along the fluid path beginning at 121, is connected

with the barrier fluid reservoir at connection 123 and passes through the barrier fluids 121 and 122 inside the chamber 118, exits via connection 119 and continues through the control line via connection 116 with the pressure transducer 114. In general, it is preferable to allow the end of the sensor and cable assembly to pass the turning point 124. This has the advantage that if fluid enters the main road from the hydrocarbon reservoir side of the main road, the fluid flow will not cause the pressure sensor to change its position to a significant extent. This will also be beneficial in the event that gas enters the main road. In this design, gas will be unable to enter the sensor capillary packing and fluid barrier. Such a change in position could result in a change in the pressure reading.

It should be understood that although the main path 100 for deploying sensors in FIG. 1 is shown as a return control line, located in the annulus between the production string 11 and the casing 12, this should be considered as an example only. The assignee of the present invention has demonstrated in field tests examples of highways that have been located both inside and outside the casing. In certain situations it may be preferable to place the main roadway inside the casing, in other situations it may be appropriate or necessary to place sensors outside the casing. For example, where acoustic information from the reservoir is given a particularly high value, it is preferable to install the main road outside the casing. In another example, safety considerations may favor placement of the main path outside the casing to improve the isolation of the annulus above a packing from the zone below the packing. In yet another example, where it is necessary or desirable to monitor the condition of an electrically submerged pump, the main path is preferably located inside the casing. In still other situations, a mixture of both paths may be preferable. E.g. is it desirable to place the main path in the section above the packing outside the casing to have better acoustic coupling for reservoir imaging purposes while achieving better isolation for safe operation, but still to have the main path inside the casing for the purpose of monitoring the condition of the perforated production interval. It should also be understood that the wall of the casing 12 can be used to form a highway path for the sensors and their cables. Likewise, the main road can make use of the interior of the production string 11 or the wall of the production string for all or part of the main road circuit.

Modern drilling and completion techniques introduce other possible configurations for sensor highways to collect information from distant locations in the hydrocarbon reservoir or nearby formations. As real-time reservoir management techniques are developed, the need to have more direct information at locations within the reservoir will increase. In another embodiment of the present invention, the sensor main path may make use of small caliber, coiled tubing paths or "lances" into areas 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 borehole effects, acoustic information, without high-level interference from a producing well, compositional information outside the well's production zone, and others. The flow control elements 115 and 117 shown in Figure 1 are not necessarily required when treating oil wells whose downhole pressure exceeds the pressure exerted by a highway that is completely filled with a fluid. In the example of an overpressure well, there is very little transfer of fluid from the hydrocarbon reservoir into the main road in the event of a pressure increase during a well shut-in. Therefore, the fluids 121 and 122 will remain fully effective as a barrier between the highway fluid and the hydrocarbon reservoir fluid. In such overpressure wells, the use of the barrier fluid reservoir can also be eliminated or simplified. E.g. it can be replaced with a section of control lines containing sufficient barrier fluid to compensate for expansion of the main path during a well shut-in.

As the production of oil and gas continues over a period of time and the wells reach a condition where the pressure down the borehole drops and becomes less than the pressure from a fluid-filled main road, control of fluid transfer to and from the main road via the control elements 115 and 117 becomes important, and it also becomes the barrier fluid reservoir 118.

During the well shut-in, if there is a reduction in wellbore pressure, as occurs when well flow restarts, the fluid flow should be allowed to flow from the mainway into the barrier fluid reservoir 118 so that the sensor measures the wellbore pressure and not the pressure exerted by the column of fluid in the mainway, which will be higher than the borehole pressure if the fluid is not allowed to drain from the main road. This return flow rate is preferably high enough so that the pressure at the sensor remains representative of the current borehole pressure and is not dominated by the pressure caused by the weight of an unbalanced column of fluid in the main path above the sensor.

A second example of the first embodiment of the invention deals with the case of a negative pressure well. As fluids are withdrawn from the hydrocarbon reservoir, the operating pressure down the wellbore will decrease, and the height of the fluid column maintained in the main path will also drop. It must be expected that the downhole pressure during normal production will reach a point where the highway fluid will drop to a level below the top of the highway, leaving a section of the highway control line that does not contain fluid. In the event that a well is temporarily shut in, the resulting transient in wellbore pressure will tend to push fluid into the main path until the weight of the column balances the pressure in the wellbore. It is preferable to minimize the amount of fluid that must be transferred into the main road to equalize the pressure during shut-in of the well. This minimizes the required volume of the fluid reservoir between the main road and the wellbore fluid. Minimizing the current will also minimize the error in the sensor's reading due to pressure drop between the sensor and the wellbore. In general, it is desirable to have a fluid path between the hydrocarbon reservoir and the sensor location that has a low impedance to fluid flow. Therefore, connections from the point 121 into the barrier reservoir 118 and between 119 and the sensing location 114 are preferably as short as is appropriate, and with a bore as large as is practical.

Where a number of sensor cables occupy space inside the main road, it can prove difficult to achieve a perfect seal around the many cables. Provided that the amount of flow through this seal is sufficiently low so that the height of the liquid column does not significantly degrade the measurement of the wellbore pressure, such a leak can be acceptable. In Figure 2, as a non-limiting example, there is shown a configuration of the flow restrictor (115 in Figure 1) which preferably comprises a reservoir in the space above the sealing or throttling element to minimize the change in level within the main road 100 during a negative pressure wave in the wellbore due to poor sealing around the sensors or sensor cables inside the main road. That is, when the flow in the well starts again after a period of shut-in, or when the well flow is simply increased, the pressure in the wellbore will decrease, and will eventually cause the level of fluid inside the main road to decrease.

In its simplest form, control of the main sensor path according to the present invention, and thus control of the sensor environment, can be achieved by using only fluids of different density and viscosity down the borehole. The main reasons for wanting to maintain control of the sensor highway are (1) to maximize sensor performance and minimize measurement uncertainty, (2) to control and eliminate external fluids into the highway system, (3) elimination of potential internal highway flow paths, (4) to allow "clearing" of any small segments of the highway system that may be contaminated by extraneous material over time, and to restore full sensor measurement quality, and (5) to facilitate replacement of individual sensors in the case of many sensors in the same highway. Figure 7 shows a schematic view of an oil or gas well, equipped with a main road 700 for deploying and retrieving sensors and for performing permanent downhole measurements, including measurement of borehole pressure. Figure 7 shows a production tubing string 79 surrounded by a casing string 77, and a perforated section of the casing 710, to allow inflow of reservoir fluids from the reservoir into the well. The well is completed with a wellhead (not shown) which includes main shut-off valves (also not shown) to shut off the well. The gaskets 74 are installed to prevent the different areas of the annulus between the production pipe 79 and the casing pipe 77 from being directly connected to the different reservoir zones. The gaskets 74 are shown with high pressure penetrators 75 which allow the hydraulic control lines 78, which form part of the sensor main path 700, to pass through the gasket. The control wires are typically 1/4 inch in diameter, and are typically made of stainless steel. However, the relevant control lines for any particular well must be constructed to meet or exceed the metallurgical requirements for the well completion construction. It may be appropriate to wrap the control wires around the production string in one or more areas along the string. The control wires may be attached to the production string with clamps 714, which will also serve to protect the control wires from damage during installation. The sensor main path exits the wellhead through high pressure seals (not shown), past valves (also not shown) that serve as emergency pressure seals, and then through high pressure bushings (not shown) where the fiber optic cables exit while maintaining a pressure seal between the surrounding surface environment and the interior of the sensor highway system. The sensor backbone also includes "Y" branches 76, plug segments 72 to specific sensing locations, and connections to the interior of the production string 79 through the connection port on the side pocket door 73. The sensor backbone 700 includes fiber optic cables (not shown) and sensors (not shown). The sensors can include e.g. 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 do not necessarily have to be fiber optic types. The cable itself will not necessarily be connected to a sensor at all, but can instead be used to communicate to an optical switch that is used to remotely control valves and machinery down the borehole. It is most advantageous that the cables and/or sensors are able to be moved to the remote locations by fluid flow, and therefore benefit from being retrievable and replaceable. It is further intended that fluid segmentation and sensor isolation inside the main road should be achieved by time-controlled fluid pumping to place the various 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 drive fluid. This is achieved by using the main path control valves on the surface in conjunction with the downhole flow control valves 716 located in the side pocket mandrel 73. It may be beneficial (but not necessary) if the flow control valves in different mandrels 73 are designed 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 placed by manipulating the flow rate in conjunction with the surface control valve (not shown) and flow control valves 716 located in the side pocket door 73. Commercially available gel forming materials can be used. Hydrophilic organic polymers, such as hydratable polysaccharides and hydratable synthetic polymers, e.g. polyacrylamide, can be used to form aqueous gels. Numerous solid metallic cross-linking or complicating agents can be used to complex the hydrated gelling agents. The metallic complicating agents may include antimony salts, aluminum salts, chromium salts, and certain organic titanates. The exact location of the sensors in the highway segment 72 typically depends on the type of sensor being used. The fluid barriers 717 and gel plug 71 can then be pumped into place by isolating the surface return line and controlling the flow path through any of the highway segments 72 via the flow control valves 716 located in the side pocket door 73. Barrier fluids and gel plug construction preferably takes into account the type of contaminant and reservoir fluids expected and the maximum differential pressure that must be maintained between the segments and the main body of the main road. Additional isolation and segment protection can be achieved by placing "fiber-friendly" valves (ie, valves that can form a non-damaging seal around one or more fibers within the trunk) in the trunk plug segments 72 above where the gel plugs 71 are located.

An operational example may include a polarimetric pressure sensor available from SensorDynamics, Winchester, England. The sensor and its associated fiber optic cable can enter the main road 700 at the high pressure seal at the wellhead. The sensing portion of the assembly may be located below the location of the mainway "Y" 76 and below the location where the gel plug 71 is inserted within the mainway segment 72. The pressure is communicated to the sensor via a continuous fluid path that begins in the reservoir and enters the casing and production string and passes through the open the wellbore valve 716 in the side pocket door 73 and connects to the barrier fluid in the main road segment 72 via the port 715. In the event that the performance of the sensor is called into question or if the sensor or the cable has failed, the barrier plug 717 and the gel or segmentation 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 reinstalled along with a new barrier fluid 717 and a gel or segmentation plug 71.

Figure 2 describes a non-limiting example of the flow control element 115 of Figure 1. It should be clear that such a flow control element can be installed in one or both sections of the main road and also that the precise location along the main road can include locations above the packing as well as under the packing. In figure 2, one or more fiber sensors or cables 21 are shown placed inside the main road 22. The main road control line continues into a container 23. Inside this container, the main road control line is shown to be perforated so that fluid can easily enter the main volume of the container 23 and at the same time help ensure that the sensors and their cables are routed along the main road. The container 23 is shown to contain main road fluid 25 in the lower part of the container. This level is preferably established by checking from the surface, before the flow from the well is re-established. The purpose of the container is to reduce the change in fluid level in the main path for a given flow rate past the sealing or throttle element and thus minimize errors in the pressure measured at the sensing point. While the level of fluid is within volume 25, a small leak past the seal or choke will cause a very reduced change in column pressure.

It should be noted that the pressure at the sensing point in the wellbore is at its highest when the well is stopped. At this stage the main road fluid can be forced down to a level which is close to the bottom of the container 23 by using e.g. nitrogen gas under pressure from the surface. The seal or choke is then closed and the nitrogen gas pressure is released. The use of the term throttle in this context is intended to indicate a significant reduction in flow past the device. The column of liquid in the main road will then be under positive pressure from the wellbore. That is, if the throat member were to be opened, the wellbore pressure would cause the fluid to flow in an upward direction and reach a level above the throat member before the pressure exerted by the fluid column balances the wellbore pressure. For the purpose of accurately monitoring the dynamics of the wellbore pressure, it is preferable to have the throttle element closed, and where a fluid reservoir 23 is included, to have the reservoir at least partially filled with main road fluid. The sensor reads the wellbore pressure under these conditions. When the flow is restarted in the well, the pressure in the wellbore will drop, but will remain greater than the pressure from the fluid in the main road provided that the seal or choke is placed low enough in the main road. The main road control line 26 is shown to be connected to the sealing or throttle assembly 27 containing a remotely controllable gasket or throttle 28, and to continue as section 210. The line 29 indicates remote control of the throttle. Different methods can be used to exercise control. One method is to have an independent hydraulic control line that leads from the wellhead to the sealing or throat device 27. Other methods can be used, such as e.g. when the cost of the independent control line is too high. Another such method is to have a feed connection forward from a point above the gasket or throttle to the control input 29. In this way the gasket or throttle can be set from the surface without an independent control line.

The device shown in Figure 2 serves to minimize or reduce the amount of fluid flowing up through the main path in the event of a positive pressure transient in the wellbore, and also to eliminate or reduce to an acceptable value the errors that may occur at the sensor in the event of a negative pressure wave in the wellbore.

An alternative approach to the flow control device of FIG. 2 is to eliminate the reservoir 24, but retain the sealing device 27 and make use of the barrier fluid reservoir 118 in Figure 1. During normal operation, the sealing or throttle elements are set closed. If the well is closed, the wellbore pressure will increase. The sealing device 27 will prevent the movement of fluid into the main road. After the positive pressure transient information is obtained, the fluid in a section of the main road can be ejected to the surface by applying nitrogen or another gas under overpressure on one of the sections of the main road while opening the other entry point at the surface. The surface entry points close. The liquid will then sink down to the lower sections of the two main road sections. At this point, the seals or throttles 27 can be closed. An alternative method that can be used to displace the deployment fluid inside the main road is to use another liquid which has the property that it changes to the gas phase at the wellbore temperature. Under these conditions, barrier fluid will be sucked upwards into the main road if the main road is opened to the ambient pressure at the wellhead. This method is preferable where it is desirable to surround the sensor and sensor cable with barrier fluid, to minimize degradation of sensors and cables in high temperature areas. The gas in the area above the barrier fluid is preferably chosen to be an inert gas, such as e.g. nitrogen. The gas in the main path above the seal is then allowed to come to ambient atmospheric pressure temporarily to allow the gas pressure to be approximately equalized. At this stage, the wellbore pressure is at its highest, and will be higher than the pressure exerted by the fluid column in the main road. The fluid flow can now be started again, and will cause the wellbore pressure to decrease. The sensor down in the borehole at position 114 in figure 1 will register this reduction accurately, as long as the wellbore pressure exceeds the pressure exerted by the weight of the liquid column in the main road. This condition is ensured by appropriate selection of the level of the flow control device 115 in figure 1 or the device 27 in figure 2. However, for a low pressure well or a very depleted well where the pressure has dropped to a low level of e.g. 70 kg/cm , the choice of level for the flow control device can be very deep down in the oil well close to production. For example, the maximum height h of fluid of density p, between the choke and the point of well production (32 in Figure 1), which is allowed so that the well pressure is higher than that due to the column of fluid (equal to pgh , where g is the gravitational constant), may in reality be quite small (of the order of a few hundred meters). Furthermore, this level will depend very much on the density of the selected highway fluid, which can be significant if liquid metal is used. The deep location of the flow device will significantly affect the operational specifications as the temperature and pressure (in the early days of well production) can both be extreme (temperatures up to 350 °C in some steam stimulation wells). A deeply located flow device would also require a deep-reaching hydraulic additional control line if this were to be the chosen method of flow device control. However, note that if these extreme conditions do not prove to be a problem, placing the flow devices as close as possible (but still above) to the sensing areas of the fiber may be beneficial. This allows operation with the majority of the mainway empty, or flushed with dry nitrogen gas, to minimize the area of the mainway that needs to be filled with an inert fluid with a low water content (eg, a silicone oil or a liquid metal). Most of the downcomer cable may be exposed to high temperatures, but in dry nitrogen gas, an environment that has little effect on the cable. This construction reduces the required volumes of barrier fluid in the main road.

As oil and gas wells must function over long periods, it is also desirable that such devices have an equally long lifespan, or that they can be easily retrieved and replaced, without requiring the shutdown of normal well production. Deployable valves capable of sealing around fiber cables and which can be pumped along the main road and placed in suitable locations are shown in US 6,006,828.

It should also be obvious that an independent pressure sensor can be placed in the main path to sense the position of the liquid in the main path. Preferably, this pressure sensor is located far from the position 114 which is chosen to monitor the wellbore pressure. The optimum point for this is immediately below the lowest equilibrium liquid level that can be expected during the lifetime of the hydrocarbon reservoir. In a negative pressure well, this sensor will record the pressure due to the column of liquid above the sensor. This information can be used to model the effect of fluid flow in the main path and to improve the data obtained by the primary pressure sensor located near the wellbore at position 114 in Figure 1.

The device 117 that controls the flow of fluid between the barrier fluid reservoir and the sensor highway control lines 19 in Figure 1 preferably includes the following features: While the sensors are about to be deployed, the fluid flow from the highway into the barrier fluid reservoir is kept at a low amount, so that the flow in both sections of the main road is sufficient to move the sensors and cables. One solution, which is given as a non-limiting example only, is to have a valve that allows downward flow from the main path up to a critical flow rate, at which point the valve closes to reduce or stop the flow. This can be achieved by positive pressure from the surface at the start of any deployment operation.

When the flowing well is shut off and the well pressure rises, the impedance for fluid transfer from the fluid barrier reservoir into the main road is preferably low in the area between the barrier fluid reservoir and the position of the pressure sensor, so that the pressure at the sensor is representative of the wellbore pressure, and is not dominated by pressure drop between the pressure communication point 121 and the sensor location 114. Choosing the largest possible bore for the fluid path reduces the impedance. The volume control unit 117 is preferably replaceable if it becomes sticky or damaged. One method of accomplishing this is shown in US 6,006,828.

Referring to Figure 3, a non-limiting example of a barrier fluid assembly 300 is shown. The main path containing the pressure sensor 31 (and possibly other sensors) is connected to a first barrier fluid reservoir section 320 at a connection 33. This reservoir is shown to contain a first barrier fluid 34 and a second barrier fluid 35. The connection may contain a flow control device 32. The first barrier fluid reservoir section 320 is connected to a second barrier fluid reservoir section 330 by a connection 38. The second barrier fluid reservoir contains the second barrier fluid 35 and may also contain fluid 37 which is the same hydrocarbon fluid as the wellbore fluid 37. The barrier fluid 34 has a lower density than the barrier fluid 35, and the two fluids are preferably not miscible. The fluid 35 may be chosen to be a fluid, such as an indium-based alloy, which is in a liquid state at the wellbore temperature and which has a low propensity to react chemically with the hydrocarbon wellbore fluids. Preferably, the fluid 35 will also minimize diffusion of molecular substances from the wellbore fluid. It should be noted that a single barrier fluid may be sufficient in wells where the borehole fluid is sufficiently favorable chemically. Likewise, it is possible to realize a construction comprising a single reservoir container, even if two or more barrier fluids are used, provided that the relative densities are such that arrangement of the fluids according to the densities achieves the objectives.

It should also be noted that if either the barrier fluid 34 or the fluid 35 becomes contaminated or degraded, it will be possible to displace these into the wellbore and replace the fluids with new fluids without requiring the well to be shut down. This can be achieved e.g. by injecting fluids 34 or 35 at the wellhead through the hydraulic control line. If the surrounding well surface temperature is lower than the melting points of these fluids, these materials can be injected in the form of small balls. These balls will turn to liquid at a depth where the well temperature exceeds the melting point of the ball material.

The barrier fluid 34 is preferably a liquid metal such as gallium or another metal which is in a liquid state at the wellbore temperature, and which has a lower density than the fluid 35 and which does not tend to mix with the fluid 35. This fluid 34 can also be a non-metallic fluid which is inert in relation to the fluid 35 and in relation 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 inside the highway control line 31 and thus minimize errors in the measurements at the pressure sensor due to flow-induced pressure gradients between the pressure communication point 31 and the position of the pressure sensor.

A configuration with multiple barrier fluids in Figure 3 can also be achieved with an annular vessel similar to that shown in the separate plan detail in Figure 1. The choice of one or the other configuration depends on the ease of manufacture and inclusion in a particular well.

Figure 4 shows the control line main path 41 which contains one or more sensors which are connected to a barrier fluid reservoir 43 via a control line section which may include a flow control device 42. The hydrocarbon reservoir fluid 45 is allowed direct access to the interior of the barrier fluid reservoir at a point 46, and can enter the chamber 43.1 the barrier fluid container 43 shows a fluid 44 which acts as a fluid barrier between the wellbore fluid 45 and the sensor and its package. It must be understood that a further fluid may be in the main road in the area where the sensor is located or above it. A mechanical piston 47 is shown which separates the fluids 44 and 45. This piston can contain a small caliber connection 48 which can be filled with fluid 44. The piston assembly communicates the borehole pressure to the interior of the main road. When conditions are such that a large movement of fluid is required to move into or out of the main path, the position of the piston will be adjusted in response to the existing pressure difference. Small errors can be introduced by static friction in the piston, but these will make up a small part of the total change. When very small changes in pressure occur, it is preferable to have a direct fluid-to-fluid contact, since static friction in the mechanical piston can hide such small changes or introduce errors that are large in relation to the changes to be measured. Such small pressure changes usually occur in well tests after the first large transient. These signals contain important information about the hydrocarbon reservoir, and are of great interest to reservoir engineers. The fluid to fluid contact will bypass this shortcoming, and therefore allows very small pressure changes in the wellbore to be accurately measured by the sensor in the main path. On the other hand, the small caliber fluid connection 48 itself will not be able to respond to large pressure changes without causing significant errors to occur over a period of time necessary for the fluid transfer to occur.

The mechanical piston can be designed so that it can be replaced by a wire or smooth wire intervention or by using a robotic vehicle.

It will also be clear to those skilled in the art that alternative designs can be devised which achieve the purposes of the device in fig. 3 in which mechanical devices can be used.

Figure 5 shows a non-limiting example of a device which produces a mechanical isolation or separation of reservoir fluids from main road fluids. A membrane 52 is shown in an annular space 50 around a production string 51. The membrane divides the annular space into two areas. On one side of the membrane there is a space that contains a fluid 54. On the other side of the membrane there is a space that contains fluid 55. The fluid 55 is reservoir fluid, also shown as 56. The reservoir fluid 56 can enter the adjacent annulus by a or several ports 53. The fluid 54 can be the same fluid as that used in the main road 57 which is connected to the outer annulus by a port 59. If the pressure inside the production string changes, this change in pressure is communicated to the fluid inside the main road. The diaphragm adjusts its position in response to pressure changes. It is important to adjust the initial position of the membrane by applying pressure to the main path at the surface. The preferred static position of the membrane when the well is closed and where the wellbore pressure is therefore at its highest, should be close to the outer wall of the annulus. When the well is flowing at maximum volume, the wellbore pressure will generally be at its lowest. Transition from shut-in well to flowing well can cause fluid transfer from the main path into the annular swing chamber. The size of the total annulus has been chosen to be sufficient for the particular well conditions. When large changes in pressure are expected, the length of the annular swing chamber must be greater than in wells where relatively small changes are expected. When flow restrictors 510 are built into the main path above the position of the pressure sensor, the size of the required chamber is reduced. Generally, the preferred position of the pressure sensor is within the main path near the connection with the annular swing chamber (shown as 511 in Figure 5).

Claims (16)

1. Device for isolating a sensor from an environment at a remote location in a borehole where the sensor (31, 65) senses one or more physical parameters, characterized in that it comprises a first control line (19, 22, 57, 62, 78 ) which contains a communication cable and a sensor (31, 65) in connection therewith, where the sensor (31, 65) is placed inside the first control line (19, 22, 57, 62, 78) near the remote location, a second control line having a first end (116) in fluid communication with the first control line (19, 22, 57, 62, 78) near the sensor (31, 65), and a second end (119), and a fluid barrier reservoir (118, 23, 320, 330, 43) containing a barrier fluid (122, 34, 717), where the fluid barrier has a first opening in fluid communication with the second end (119) of the second control line, and a second opening (123) in fluid communication with the remote place. 2. Device according to claim 1, characterized in that it further comprises a first flow control element which is placed inside the second control line between the first control line and the fluid barrier reservoir, the first flow control element being designed to be activated between a first state that allows fluid flow in the second control line in any direction, and a second condition that restricts fluid flow in the second control line from the barrier fluid reservoir to the first control line. 3. Device according to claim 2, characterized in that it further comprises a second flow control element which is placed inside the first control line, the second flow control element being designed to be activated between a first state that allows a fluid flow in the first control line in any direction, and a second condition that restricts fluid flow from the first guide line. 4. Device according to claim 1, characterized in that it further comprises a gel plug which is placed inside the second control line between the first control line and the barrier fluid reservoir, the gel plug comprising a volume containing a gel which is chosen to isolate the barrier fluid chemically from fluids inside in the first management. 5. Device according to claim 4, characterized in that it further comprises a pipeline which has a first end in fluid connection with the barrier fluid reservoir, and a second end in fluid connection with the remote location, and further comprises a fluid-activated control valve which is placed inside the pipeline , the fluid actuated control valve responding to open when fluid is pumped through the pipeline and the first and second control lines. 6. Device according to claim 1, characterized in that it further comprises a fluid moving device for introducing fluid into the first and second control lines, and a fluid volume measuring device which is designed to measure the volume of fluid introduced into the first and second control lines of the fluid moving device. 7. Device according to claim 1 for sensing one or more physical parameters at remote locations, characterized in that it comprises a number of sensors in connection with the communication cable, each sensor being placed inside the first control line near a respective remote location, and a number fluid barrier sensing sections, each fluid barrier sensing section comprising a second control line having a first end in fluid communication with the first control line near one of the sensors, and a second end, and a fluid barrier reservoir containing a barrier fluid, the fluid barrier having a first opening in fluid communication with the other end of the associated second control line, and a second opening in fluid communication with the associated remote location. 8. Device according to claim 1, characterized in that the communication cable is a fiber optic cable. 9. Fluid barrier (122, 34, 717) for isolating a sensor (31, 65) located within a first control line (19, 22, 57, 62, 78) from an environment at a location near the sensor (31 , 65), characterized in that it comprises a fluid line which has a first end (116) in fluid connection with the first control line (19, 22, 57, 62, 78) near the sensor (31, 65), and a second end (119 ), and a first fluid barrier reservoir (118, 23, 320, 330, 43) having a first opening in fluid communication with the remote site, and a second opening in fluid communication with the other end of the fluid line (119), the first opening being distal from the second opening, the first fluid barrier reservoir (118, 23, 320, 330, 43) containing a first fluid having a first specific gravity. 10. Fluid barrier according to claim 9, characterized in that it further comprises a second fluid barrier reservoir which is placed inside the fluid line between the first fluid barrier reservoir and the first control line, the second fluid reservoir having first and second openings for connection with the fluid line, the first opening being distal from the second opening, the second fluid barrier reservoir containing a second fluid having a second specific gravity different from the first specific gravity. 11. Fluid barrier according to claim 10, characterized in that the second fluid barrier reservoir is placed elevationally higher than the first fluid barrier reservoir, and that the first specific weight is greater than the second specific weight. 12. Fluid barrier according to claim 11, characterized in that it further comprises a fluid-activated control valve which is placed inside the first fluid line between the second fluid barrier reservoir and the first control line, the fluid-activated control valve reacting to open when fluid is pumped through the fluid line towards the other and first fluid barrier reservoirs. 13. Fluid barrier according to claim 10, characterized in that the first and second fluids are essentially immiscible with each other, and that the first fluid is chosen to be essentially chemically inactive with an environment at the remote location. 14. Method for chemically isolating a sensor (31, 65) from a place where a parameter is to be measured by the sensor (31, 65), the place being located in a fluid environment in a borehole, characterized in that it includes placement inside a control line (19, 22, 57, 62, 78) of a sensor in signal connection with a communication cable (21), the sensor (31, 65) being located in a section of the control line (19, 22, 57, 62, 78) near the location at which the parameter is to be measured, placement of a fluid reservoir (118, 23, 320, 330, 43) in fluid communication with the section of the control line (19, 22, 57, 62, 78) containing the sensor (31, 65), as the fluid reservoir (118, 23, 320330, 43) is further placed in fluid connection with the fluid environment, insulation of the control line (19, 22, 57, 62, 78) to prevent the passage of fluid into the control line (19, 22, 57, 62 , 78) from the fluid environment, and introducing a first fluid into the control line (19, 22, 57, 62, 78) to cause the first fluid to flow into in the fluid reservoir (118, 23, 320, 330, 43). 15. Method according to claim 14, characterized in that it further comprises measuring the volume of the first fluid which is led down through the control line and into the fluid reservoir, and stopping the flow of the first fluid into the control line when a sufficient volume of the first fluid is been passed down through the control line to fill at least a portion of the fluid reservoir. 16. Method according to claim 14, characterized in that it further comprises placing a second fluid reservoir in flowing fluid connection with the section of the control line containing the sensor and the fluid reservoir, and introducing a second fluid into the control line to cause the second fluid to flow in in the second fluid reservoir.