System and methods using fiber optics in coiled tubing

[0001] The present invention relates generally to operations in an underground wellbore, and in particular to the use of optical fibers and optical fiber components, such as cables and sensors, used in operations carried out by means of coiled tubing.

Background of the invention [0002] When operating an underground well, for example drilled in an oil field, it is often necessary or desirable to perform well work in order to, for example, extend the well's life, improve production, gain access to the underground zone, or respond to a situation that occurred during the works. It is known that coiled tubing is preferred for such work. The use of coiled tubing is often faster and more economical than the use of combined tubes and drilling equipment to perform work in the wellbore, with the coiled tubing enabling transportation in non-vertical or branched wells.

[0003] Although operations carried out by means of coiled tubing are carried out deep underground, personnel or surface devices control operations. In general, however, there is a lack of information on the surface regarding the condition of the bottom piping operations. When there is no data transfer between the tool surface, it is not always possible to drill or condition the tool.

Possible error-free in the well and state of affirmation [0004] Coiled tubing is particularly useful for wellbore operations with fluids, one or more fluids being pumped into the wellbore through the inside of the coiled tubing or through a ring between the coiled tubing and the hole well. Such treatments may include generating circulation in the wellbore, removing proppant, stimulating the reservoir, removing rock, crushing, isolating zones, etc. Coiled tubing allows these fluids to be delivered to a specific depth in the wellbore. Coiled tubing can also be used to intervene in a wellbore to allow, for example, to retrieve lost devices or to place or manipulate devices in a wellbore.

[0005] When introducing pressurized coiled tubing into the wellbore, a continuous section of the coiled tubing passes from the spool through the wellhead seals deep into the wellbore. Fluid flow through the coiled tubing can also be used to supply hydraulic energy to the tool assembly attached to the end of the tubing. A typical set of tools may include one or more non-return valves so that if the piping fails, the non-return valves will close and prevent well fluid from escaping. Because of the flow requirements, there is usually no system for direct data transmission between a set of tools and will tell surface. Other devices used with coiled tubing can be triggered hydraulically. Some devices, such as installation tools, can be triggered by the sequence of pulling and pushing the tool assembly, but, again, the surface operator does not know the condition of the tools at the bottom of the well.

[0006] Similarly, it is important to be able to accurately estimate the depth at which a set of tools in a well are. Direct measurement of the length of the coiled tubing, attached to the tool assembly and inserted into the wellbore, may not, however, accurately represent the depth at which the tool assembly is located, since the coiled tubing is subjected to spiral coiling during the descent along the well casing. The spiral winding effect means that it is impossible to estimate the depth at which the tool is supplied by the rolled pipe.

[0007] The difficulty of collecting and transmitting accurate data from depth to surface often causes an incorrect representation of well conditions for personnel who make decisions regarding operations performed in the transmission of information about well operations

It is desirable in a borehole to the surface, it is especially desirable that the information is transmitted in real time to allow correction of the operation. This can increase productivity and reduce the cost of borehole operations. For example, the availability of such information will enable staff to better handle the tool assembly located in the well, more accurately position the tool assembly, or confirm proper operation of the well.

[0008] Methods of transmitting data from wellbore operations to a surface, such as using fluid pulses and wired cables, are known. Each of these methods has significant disadvantages. Pressure pulse transmission uses fluid pressure pulses to send a modulated pressure wave to the surface. This wave is then demodulated to retrieve the transmitted bits. This method of transmission can provide data with a small number of bits per second, but at higher transmission rates, the signal is strongly attenuated due to the properties of the fluid. In addition, the method of producing signals absolutely requires a temporary suspension of flow; this is often undesirable in borehole operations.

[0009] It is known to use electric or wired cables in coiled tubing for transmitting information during well operations. It has been suggested to provide a wired cable with coiled tubing, the cable being supplied outside the tubing. Such external delivery is difficult to perform and threatens to collide with well components. The need for specialized equipment and procedures, and the likelihood that the cable will wrap around the coiled tubing when lowered, make this method undesirable. Another known technique relies on embedding a cable or data channels in the wall of the pipe itself. This configuration has the advantage that the entire inner diameter of the pipe can be used to pump fluids, but also has the major drawback that there is no convenient way to repair such pipe in the field. It is not uncommon during operations using coiled tubing that the tubing is damaged and in this case the damaged section must be removed from the coil and the remaining fragments must be welded. In the presence of built-in cables or data transmission channels, welding operations can be complicated or simply impossible.

[0010] It is known to lower a wired cable within a coiled tubing. Although this method provides some functionality, it also has drawbacks. First, it is not easy to insert the cable into the pipe coil. Fluid is used to transport a wired cable to a pipeline and a large, high-pressure winch is needed to move the cable along with the fluid. U.S. Patent No. 5,573,225, entitled Means For Placing Cable Within Coiled Tubing, by Bruce W. Boyle et al, incorporated herein as a source material, describes a device for installing an electric cable in a coiled tubing.

[0011] In addition to the difficulty of installing the cable in the coiled tubing, the relative size of the cable relative to the internal diameter of the coiled tubing, as well as the weight and cost of the cable, discourage the use of the cable inside the tubing.

[0012] Electrical cables, used in operations using coiled tubing, typically have a diameter of 0.25 to 0.3 inch (0.635 to 0.762 cm), while the diameter of coiled tubing is generally in the range of 1 to 2.5 inch (2.54 to 6.350 cm ). The relatively large outer diameter of the cable relative to the relatively small inner diameter of the pipe reduces the cross-sectional area available for fluid flow in the pipe. In addition, the large external surface area of ​​the cable introduces frictional resistance for the fluid pumped through the pipe.

[0013] The weight of the wired cable provides yet another disadvantage in using it in coiled tubing. Known electrical cables used in coiled tubing used in oil field operations can weigh up to 0.35 pounds / foot (2.91 kg / m) so that 20,000 feet (6095 cm) of electrical cable can add an additional 7,000 pounds (3,175 kg) to weight of the coiled tubing. By comparison, a typical 1.25-inch (3.175 cm) roll-up tubing weighs about 1.5 pounds / foot (12.5 kg / m), giving a total of 30,000 pounds (13,608 kg) for a 20,000-foot (6096 cm) length pipe. Consequently, the electric cable increases the system weight by about 25%. Such heavy equipment is difficult to handle and often prevents the installation of a coiled tubing equipped with a conduit. In addition, the weight of the cable causes it to stretch under its own weight to a different degree than the stretching of the piping, which results in the introduction of slack in the cable. The clearance must be controlled to avoid breaking and tangling ("creating a bird's nest") of the cable in the pipe. Controlling the slack includes, in some cases, shortening the cable or tubing, in order to obtain sufficient slack in the cable, may increase the time and cost of handling coiled tubing.

[0014] There are other difficulties when using a wired cable inside coiled tubing for data transmission. For example, to receive data from a transmission line in a cable, you need a data collector that can rotate with the spool, while not tangling the portion of the wire that is outside the spool (e.g., a wire that is connected to a computer on the surface ). Such known devices are susceptible to damage and expensive. In addition, the cable itself is subject to wear and degradation as a result of fluid flow in the pipe. External cable armor can also create operating problems. In some operations on the well, the coiled tubing is cut to seal the well as soon as possible. Shears optimized for cutting coiled tubing, however, are usually not effective when cutting armored cable.

[0015]

US Patent 6,192,983, which is considered the closest document of the current state of the art, describes a tubular, known as tubular, which includes the form of a "electric, coiled high energy coiled cable, data transmission cables and hydraulic hoses within the coiled tubing, as well as include fiber optic cable. The electric coiled tubing is basically similar to a coiled tubing with a wired cable inside it, but with the addition of an amber tube, and therefore has the same disadvantages.

[0016] Patent application GB 2 275 953 from Wielka

Britain describes a well logging tool hanging from a coiled tubing that includes communication and power cables that may include optical fibers.

[0017] It follows from the above that there is a need for systems and methods for collecting and transmitting data to and from operations carried out in the wellbore using coiled tubing to the surface without disturbing the operations performed in the wellbore. Arrangements and methods for collecting and transmitting such information in a timely, efficient and economical manner are particularly desirable. The present invention overcomes the difficulties of the prior art and meets these needs.

Summary of the Invention [0018] The present invention provides methods for working in a wellbore or for borehole operations or wellbore operations, including inserting a fiber optic cable into a coiled tubing, lowering the coiled tubing into a wellbore, and transmitting information from the well using a fiber optic cable.

[0019] In one aspect, the present invention provides a method of performing operations in an underground formation, cut through a wellbore, the method comprising the steps of: lowering the coiled tubing into a wellbore; performing treatments in the wellbore using a retractable pipe; obtaining the measured size in the well and sending the measured size to the surface; the method is characterized by inserting a fiber optic cable into the coiled tubing, the fiber optic cable having a certain clearance relative to the coiled tubing and using a fiber optic cable to transfer measured quantities to the surface, the method being further characterized by that the borehole surgery operation includes at least one adjustable parameter and the acquisition of the measured size and control of the adjustable parameter concurrently with each other and with the borehole surgery operation. Often, surgery to perform a wellbore involves injecting at least one fluid into the wellbore, for example, injecting fluid into the coiled tubing, into the wellbore ring, or into both. In some operations, more than one fluid may be injected or different fluids may be injected into the coiled tubing and ring. A borehole surgery may involve delivering fluids to stimulate hydrocarbon flow, or to inhibit the flow of water from an underground formation. In certain embodiments, the operation of performing the wellbore operation may include communication via fiber optic cable with the tool in the wellbore, and in particular communication from surface devices to the tool in the wellbore. The measured size can be any quantity that can be measured in the wellbore, including but not limited to, pressure, temperature, pH, sediment size, fluid temperature, depth, gas pressure, chemical luminescence, gamma radiation, resistance, salinity, flow fluid, compressibility, tool location, housing orifice locator presence, tool condition, and tool orientation. In specific embodiments, the measured size may be a set of measurement results taken in a well fragment, e.g., in a branch of a branched well. The borehole surgery operation parameter can be any parameter that can be adjusted, including, but not limited to, the amount of fluid injected, the relative proportion of each fluid in the set of injected fluids, the chemical concentration of each material in the set of injected materials, the relative proportion of pumped fluids in the ring for fluids pumped in the coiled tubing, concentration of released catalyst, concentration of polymer, the concentration of the proppant for fracturing and the position of the coiled tubing. The method may further include withdrawing the coiled tubing from the wellbore or leaving the fiber optic cable in the wellbore.

[0020] According to another aspect, the invention provides a device for performing a treatment in an underground formation cut through a wellbore, the device comprising: a coiled tubing to lower into a wellbore to perform a wellbore surgery; means for obtaining the measured size in the wellbore and means for transmitting the measured size to the surface; wherein the device is characterized in that the transfer means include a fiber optic cable located inside the coiled tubing, the fiber optic cable having some clearance relative to the coiled tubing, and furthermore the device is characterized by that the borehole surgery operation includes at least one adjustable parameter and the control of the adjustable parameter concurrently with obtaining the measured size and performing the surgery operation inside the wellbore.

[0021] Other features and advantages of the present invention will become apparent from the following detailed description, read with reference to the accompanying drawings, exemplifying the principles of the invention.

Brief Description of the Drawings [0022] Figure 1 schematically illustrates a device with a coiled tubing (CT) used in wellbore operations.

[0023] Figure 2A is a cross-sectional view taken along the vertical axis of an exemplary coiled tubing device using a fiber optic system in coiled tubing operations.

[0024] Figure 2B is a cross-sectional view of the device with coiled tubing with optical fiber along the line aa in Figure 2 (a).

[0025] Figure 3A shows a cross-sectional view of the first embodiment of the surface termination of an optical fiber cable according to the invention.

[0026] Figure 3B shows a cross-section of a second embodiment of the surface termination of an optical fiber cable according to the invention.

[0027] Figure 4 shows a cross section of the lower end of an optical fiber cable.

[0028] Figure 5A or 5B schematically illustrates the general case of a lower sensor connected to a fiber optic cable for transmission of an optical signal by a fiber optic cable, the optical signal being representative of the measured quantity.

[0029] Figure 6 schematically shows a wellbore operation performed using a device with a coiled tubing comprising an optical fiber cable according to the invention.

[0030] Figure 7 schematically illustrates the cleaning operation, improved by using a coiled fiber optic tubing according to the invention.

[0031] Figure 8 schematically illustrates a coiled tubing transporting a perforating system according to the invention, wherein the coiled tubing device equipped with an optical fiber is adapted to perform perforating operations.

[0032] Figure 9, for example, illustrates bottom flow control in which a fiber optic controlled valve is used to control the flow of fluids from the wellbore and reservoir.

Detailed description [0033] In the following detailed description and in several figures, the same elements are indicated by the same reference numerals.

[0034] According to the present invention, operations such as performing a wellbore treatment can be performed in the wellbore using a coiled tubing within which an optical fiber cable is located, the optical fiber cable can be used to transmit signals or information from the wellbore to the surface or from the wellbore surface. The capabilities of such a system provide many advantages over performing such operations using existing transmission methods and allow many hitherto unattainable applications of the coiled tubing in wellbore operations. The use of optical fibers in the present invention provides advantages because the optical fibers are lightweight, have a small cross-sectional area and a large transmission bandwidth.

[0035] Figure 1 shows schematically a device, in particular a surface device, used to perform services or operations using a coiled tubing in an underground wellbore. The device with coiled tubing can be delivered to the well site using a truck 101, sleigh or trailer. Truck 101 supports the coil 103 of the coiled tubing, which includes a number of coiled tubing 105 coiled on it. One end of the coiled tubing 105 terminates at the central axis of the spool 103 in the spool installation 123 that allows fluids to be pumped into the coiled tubing 105 while the spool is rotating. The other end of the coiled tubing 105 is positioned in the borehole 121 through the injector head 107 through the flushing neck 109. The injector head 107 inserts the coiled tubing 105 into the wellbore 121 through various wellhead surface control devices, such as the explosion prevention stack 111 and the main control valve (113). Coiled tubing 105 may carry one or more tools or sensors 117 at its lower end.

[0036] The coiled tubing truck 101 may be some other mobile unit for transporting the coiled tubing or a structure permanently installed in the wellbore area. Coiled tubing truck 101 (or an alternative thereof) also supports some surface control devices 119, which typically include a computer. Surface control device 119 is connected to the injector head 107 and spool 103 and is used to control the insertion of the coiled tubing 105 into the borehole 121. Control device 119 is also used for tool and sensor control operations 117 and to collect all data transmitted from the tools and sensors 117 to the surface. Monitoring device 118 may be supplied with control device 119 or separately. The connection between the coiled tubing 105 and the monitoring device 118 and / or control device 119 may be a physical connection, for example by means of communication lines, or it may be a virtual connection by means of wireless transmission or in accordance with known communication protocols such as TCP / IP. One such wireless communication system that can be used in the present invention is described in US Patent Application No. 10 / 926,522, incorporated herein in its entirety as a source material. In this way, it is possible for the monitoring device 118 to be located some distance from the wellbore. In addition, monitoring device 118 can, in turn, be used to send received signals to remote locations using methods such as those described in US Patent 6,519,568, incorporated herein by reference.

[0037] In Figure 2A, a cross-sectional view of a device 200 with a coiled tubing according to the invention is shown, which comprises a coiled tubing 105, a fiber optic cable 211 (comprising in the embodiment shown an outer protective tube 203 and one or more optical fibers 201), a surface termination 301, bottom end 207 and surface pressure barrier 213. The surface pressure barrier 213 is mounted in the reel 103 of the coiled tubing and is used to seal fiber optic cable 211 inside the coiled tubing 105, thereby preventing the release of treatment fluid and pressure while providing access to fiber optic 201. Lower end 207 provides both physical and and optical connections between optical fiber 201 and one or more optical tools or sensors 209. Optical tools or sensors 209 can be tools or sensors 117 of coiled tubing operations, can be components thereof, or provide functionality regardless of the tools and sensors 117 that performed coiled tubing operations. Surface end 301 and bottom end 207 are described in more detail below with reference to Figures 3 and

4.

pressure sensors 209 for [0038] Exemplary optical tools and include temperature sensors and sensors for determining temperature or pressure at the bottom of the well. An optical tool or sensor can also measure formation pressure or temperature. In alternative embodiments, the optical tool or sensor 209 is a camera operated to provide an optical image of the state at the bottom of the wellbore, e.g. deposits of sand or rock accumulated on the wall of the production pipe or equipment at the bottom of the well, e.g. equipment to be recovered during the fishery operation. The tool or sensor 209 may similarly be some form of measuring tip that can detect or suggest physically detectable conditions in a wellbore, e.g., sand or rock deposits. Alternatively, the tool or sensor 209 is a chemical analyzer that performs some type of chemical analysis, e.g., determining the amount of oil and / or gas in a fluid in a wellbore or measuring the pH of the fluid in a wellbore. In such cases, the tool or sensor 209 is connected to an optical fiber cable 211 to transfer measured quantities or states to the surface. Thus, when tool or sensor 209 measures the size or condition in the wellbore, fiber optic cable 211 provides a wire for transmitting or transferring the measured quantities.

[0039] Alternatively, the tool or sensor 209 is an optically activated tool, such as an actuated valve or perforating heads. In embodiments involving perforating heads, firing codes may be transmitted using fiber optics in fiber optic cable 211. The codes may be transmitted in one fiber and decoded by a device in the wellbore.

Alternatively, fiber optic cable 211 may contain a plurality of optical fibers and the actuator heads are connected to separate fibers unique to a given head.

Transmission of firing signals through fiber optic 210 of fiber optic cable 211 prevents crosstalk and pressure pulse interference that may occur when using electric wire or wired cable or pressure pulse transmission to transmit signals to actuators. Such interference may lead to the wrong guns starting or firing at the wrong time.

[0040] In Figure 2B, a cross-sectional view of a device 200 with a coiled tubing equipped with an optical fiber is shown, in which the optical fiber cable 211 includes one or more optical fibers 201 located inside the protective tube 203. The optical fibers may be multi-mode or single-mode . In some embodiments, the protective tube 203 contains metallic material, and in specific embodiments, the protective tube 203 is a metallic tube containing Inconel^™, stainless steel, Hasetloy^™or other metallic material having adequate tensile properties as well as corrosion resistance in the presence of acid and H2S.

[0041] To illustrate, but not to limit the scope of the invention, optical fiber cable 211 has a protective tube 203 with an outer diameter in the range from about 0.071 inches (1.803 mm) to about 0.125 inches (3.175 mm), with the protective tube 203 being formed around one or more optical fibers 201. In a preferred embodiment, standard optical fibers are used and the thickness of the protective tube 203 is not greater than 0.020 inches (0.508 mm).

It has been found that the inner diameter of the protective tube may be larger than necessary for tight packing of optical fibers. In alternative embodiments, fiber cable 211 may include a bare fiber cable or a cable containing optical fibers coated with a composite material, an example of such a fiber coated cable is Ruggedized Microcable, manufactured by Andrew Corporation, Orland Park, Illinois.

[0042] The lower end 207 may further be connected to one or more tools or sensors 117 to perform operations such as measurement, treatment or intervention in which signals are transmitted between surface control device 119 and the tools or sensors 117 in the wellbore along the cable fiber optic 211. These signals can transfer measurement results from tools and sensors 117 in the wellbore or transfer control signals from the control device to tools and sensors 117 in the wellbore. In some embodiments, the signals can be carried in real time. Examples of such operations include parent rock stimulation, proppant removal, fragmentation, rock removal, isolation of zones, perforation using a coiled tubing, flow control in the wellbore, manipulation of wellbore finishing, fishing, milling and drilling using the coiled tubing.

[0043] Fiber optic cable 211 may be placed in the coiled tubing 105 by any means, in particular one is the use of fluid flow. One way to accomplish this is to attach one short end, for example five to fifteen feet (1.524 m to 4.572 m), a hose to the reel of the coiled tubing 103, and the other end to the end Y. Fiber optic cable 211 can be inserted into one branch of the Y end and fluid can be pumped to the other branch of the Y end. Fluid pulling force exerted on the cable moves the fiber cable through the hose and then into the coiled tubing 103. For example, when the outer diameter fiber optic cable is less than 0.125 inch (0.3175 cm) (and the cable is made of Inconel^™), a pumping speed of 1 to 5 barrels per minute (159 to 759 liters per minute) proved sufficient to shift fiber optic cable 211 along the length of the coiled cord 105 even when coiled on a spool. The ease of performing this operation is a significant advantage over the complicated methods previously used to place a wired cable in a coiled tubing.

[0044] In practice, a sufficient length of optical fiber cable 211 must be provided so that when one end of the cable projects from the spool shaft, the other end of the cable is still outside the coiled tubing. An additional 10-20% fiber optic cable may be needed to allow clearance control when the coiled tubing is unwound to and coiled from the wellbore. When the required length of cable is pumped into the reel, the cable can be cut off and the hose disconnected. The cable protruding through the spool shaft can be terminated as shown in Figures 3A and 3B. The lower end of the cable may be terminated as shown in Figure 4.

[0045] Figures 3A and 3B show cross sections of two alternative embodiments of the surface end 301 of an optical fiber cable 211 and the surface pressure barrier 213. In many applications, it is possible to terminate fiber optic cable 211 by routing it around a 90 degree bend of a tee or connector that is not along the fluid flow axis in the coiled tubing, the tee or connector being preferably connected to the spool installation 123 on the spool axis 103. Because high pumping speeds, balls and abrasive fluids can increase the likelihood of damage to the installation, it is desirable in some embodiments to provide a surface finish.

[0046] Figure 3A shows a cross-section of a first embodiment of a surface termination of an optical fiber cable 211 according to the invention. In the embodiment shown, the surface end 301 includes a connector having a major branch 303 that is along the axis of the coiled tubing 105 and a transverse branch 305 that is deflected from the axis of the coiled tubing 105. Fluid flow follows the path defined by transverse branch 305, and fiber optic cable 211 runs along main branch 303. Connecting mechanism 313 for introducing fluids into the coiled tubing 105 can be provided at the end of transverse branch 305. The surface end 301 is connected to the coiled tubing 105 or the installation 123 coiled tubing in the orifice 309 which forms a seal with the coiled tubing 105 or the installation 123 coiled tubing. Fiber optic cable 211 passes from the coiled tubing 105 through the surface end 301 through the main branch 303. Surface end 301 has an orifice 307 attached to a pressure septum 213 that allows the fiber optic cable to pass, while maintaining pressure inside the coiled tubing 105. From surface end 301, the fiber optic cable can be connected to a control device 119, alternatively with an optical component 505, which enables optical communication with the wellbore assembly.

[0047] An embodiment of another surface finish according to the present invention is shown in Figure 3B. Surface end 301 'includes a connector having a major branch 303' that is along the axis of the coiled tubing 105 and a transverse branch 305 'which is deflected from the axis of the coiled tubing 105. In the embodiment shown, the fluid flow follows the path formed by the main branch 303 ', and the fiber optic cable 211 runs through the transverse branch 305'. The surface end 301 'may be connected to the coiled tubing 105 or to the installation 123 of coiled tubing in the orifice 309', the orifice forming a seal with the coiled tubing 105 or to the installation 123 of the coiled tubing.

[0048] Fiber optic cable 211 passes from the coiled tubing 105 through the surface end 301 'through the transverse branch 303'. Surface end 301 'includes an orifice 307' attached to a pressure septum 213 'that allows fiber optic cable 211 to pass, maintaining pressure within the coiled tubing 105. The main branch 305' may have a connecting mechanism 313 'for introducing fluids into the coiled tubing 105.

[0049] In Figure 4 is shown a cross section of one embodiment of lower end 207 for fiber optic cable 211 that provides controlled penetration of the coiled tubing 105 to the end 207. The coiled tubing 105 is attached inside the lower end 207 and is positioned in a matching him trough 403. Coiled tubing 105 can be attached to bottom end 207 using one or more set screws 405 and one or more O-rings 407 can be used to seal end 207 and coiled tubing 105. Fiber optic cable 211, located inside coiled tubing 105, protrudes from the coiled tubing 105 and is secured by connector 411. Connector 411 can also provide a connection to a tool or sensor 209. The connection formed by the link 411 can be either optical or electrical. For example, if sensor 209 is an optical sensor, the connection is an optical connection. However, in many embodiments, the tool or sensor 209 is an electrical device, and in that case connector 411 also provides all the necessary conversions between electrical and optical signals. The tool or sensor 209 can be attached to the terminator, for example by placing the lower end 415 of the terminator 207 between two concentrically extending cylinders 417 and 417 'and sealing using one or more O-rings 419.

[0050] Figures 5A and 5B show schematic illustrations of the use in the wellbore of an optical device 501 connected to an optical fiber cable 211 for transmission of an optical signal, the optical fiber cable 211 being connected on the surface to an optical device 505. An optical device 505 can be attached to the spool 103 of the coiled tubing and can rotate with it. In some embodiments, the optical device 505 may include a wireless transmitter that also rotates with the spool. Alternatively, the optical device 505 may include an optical collector having portions that remain stationary while the coil 103 of the coiled tubing rotates. An example of such a device is a fiber optic swivel connector made by Prizm

Advanced Communications Inc. in Baltimore, Maryland. An optical device 501 in a wellbore includes one or more tools or sensors 209. A tool or sensor 209 can generally fall into two categories: tools that directly produce an optical signal and those that produce an electrical signal that requires conversion to an optical signal in order to 211 fiber optic cable transmission.

[0051] Several measurements can be made, directly based on the observed optical properties, using known optical sensors. Examples of such sensors include the sensors of the types described in such books as "Fiber Optic Sensors and Applications", D.

AND. Krohn, 2000, Instrumentation Systems (ISBN No 1556177143) and include sensors with intensity modulation, phase-modulated sensors, sensors with modulated wavelength, digital switches and counters, displacement sensors, temperature sensors, pressure sensors, flow sensors, level sensors, sensors magnetic and electric field, sensors performing chemical analysis, rotation speed sensors, gyroscopes, distributed sensor systems, gels, "Smart" shells and structures.

[0052] Alternatively, tools or sensors 209 may produce an electrical signal representative of the measured quantity. When tools or sensors producing such an electrical signal are used, the optical device 501 in the wellbore further includes a device 503 providing an optical-electrical interface. Examples of optic-electrical devices and electro-optical devices are known in the industry. Examples of the conversion of traditional sensor signals into optical signals are known and described, for example, in "Photonic Analog-To-Digital Conversion (Springer Series in Optical Sciences, 81)", B. Shoop, published by Springer-BVerlag from 2001. In some embodiments of the interface device 503, a simple circuit may be used in which an electrical signal is used to turn on the light source in the wellbore and the amplitude of the light source is linearly proportional to the amplitude of the electric signal. An effective light source in the wellbore for coiled tubing operations is the InGaAsP 1300 nm light-emitting diode (LED). Light is transmitted along the fiber and its amplitude is detected on the surface using a photodiode built into the surface device 505. The amplitude value can be passed to control device 119. In another embodiment, the analog-to-digital converter is used in the interface device 503 for analysis sensor 209 electrical signal and converting it to digital signals. The digital representation can then be sent to the surface along the fiber optic cable 211 in digital form, or converted back into an analog optical signal by modifying the amplitude or frequency. Fiber optic digital data transmission protocols are very well known in the field and will not be repeated here. Another embodiment of the interface device 503 may convert the signal from sensor 209 into optical properties that can be tested from the surface, for example, it may change the reflectivity at the end of the fiber, or change the resonance of the cavity. It should be noted that in some embodiments, the optical-electrical interface and the measuring device can be integrated into one physical device and can be operated as one device.

[0053] In various embodiments, the present invention provides a method of determining a given size in a wellbore, including the steps of inserting a fiber optic cable into a coiled tubing, inserting a measuring tool into a wellbore by means of a coiled tubing, measuring a given size using a measuring tool and using a fiber optic cable for transmission of measured quantity. Such quantities may include, for example, pressure, temperature, housing orifice location, resistivity, chemical composition, flow, position, condition or setting of the tool, bed height of solid materials, sludge formation, measurement of gases such as carbon dioxide and oxygen, pH, salinity and compressibility fluid.

[0054] Knowledge of the pressure at the bottom of the well is useful in many operations performed using a coiled tubing. In certain embodiments, the present invention provides a method for an operator to optimize pressure-dependent parameters of a wellbore operation. Suitable optical pressure sensors are known, for example those that use the Fiber Bragg Grating technique and the Fabry-Perot technique. The Fiber Bragg Grating technique is based on a mesh in a small piece of fiber that locally modulates the refractive index of the fiber core itself at specific intervals. The section is then adapted to respond to physical factors such as pressure, temperature or stress. The test device is placed at the other end of the fiber and sends a broadband light beam along the optical fiber. The wavelength corresponding to the grid period is reflected towards the measuring device and is analyzed. When the physical factor changes, the grid period will change; as a consequence, the reflected wavelength will change, which is then associated with the observed physical quantity, providing a measurement result. The Fiber Bragg Grating technique has the advantage of allowing multiple measurements along one fiber. In embodiments of the present invention that use Fiber Bragg Grating, the measuring device may be placed in a surface optical device 505.

[0055] Sensors that use the Fabry-Perot technique contain a small optical cavity adapted to react to a physical agent, for example pressure, temperature, length or stress. The initial surface of the cavity is the fiber itself with a partially reflective cover, while the opposite surface is usually a completely reflective mirror. The analyzing device is located at one end of the fiber and is used to send a broadband light beam to the fiber. The sensor produces an interference system that is unique for a given bay length, so the maximum wavelength reflected on the surface corresponds to the bay length. The reflected signal is analyzed in an analyzing device to determine the maximum wavelength, which is then associated with the observed physical quantity, providing a measurement result. The limitation for the Fabry-Perot technique is that one optical fiber is needed for one measurement. However, in some of the present invention, numerous fiber optic embodiments can be provided in fiber optic cable 211, which allows the use of multiple Fabry-Perot sensors in the well bore device 501. One such pressure sensor, which uses Fabry-Perot technique and which is suitable for use in coiled tubing applications, is manufactured by FISO Technologies, St-Jean-Baptiste Avenue, Montreal, Canada.

[0056] Temperature measurements can also be made by measuring stress using Fiber Bragg Grating or Fabry-Perot techniques along fiber optic cable 211 and processing the fiber stress caused by thermally expanding the component attached to the fiber to a temperature value. In some embodiments, the sensor can be used to make local measurements, and in some embodiments, the entire temperature distribution can also be measured along cable length 211. To obtain temperature measurement, pulses of light at constant wavelength can be transmitted from the source lights in the surface device 505 along the optical fiber. At each measuring point in the fiber, the light is scattered back and returns to the surface device. Knowing the speed of light and the moment of return of the feedback signal, one can determine its origin along the fiber. Temperature stimulates the energy levels of silicon molecules in the fiber. Backscattered light contains upward or downward shifted wavebands (e.g., the Stokes Raman and AntiStokes Raman portions of the backscattered spectrum) that can be analyzed to determine the temperature at the reflection site. In this way, the temperature of each respective measuring point in the fiber can be calculated by the device, providing a full temperature profile along the fiber. Such a fiber optic system and technique for studying the temperature distribution are well known in the art. It is also known that the optical fiber can also be returned to the surface so that the entire line is U-shaped. By using the return line, the efficiency and spatial resolution can be increased, because the errors resulting from the marginal effects are far removed from the analyzed zone. In one embodiment of the present invention, the wellbore device 501 includes a small U-shaped fiber section. Bottom end 207 provides two connections between two optical fibers inside the cable with both halves of the U-shaped system so that the assembled device becomes one optical path with the return line brought to the surface. In another embodiment of this invention, the wellbore device 501 includes a device for following a particular branch of the branched well so that the temperature profile of the branch can be transmitted to the surface. Such profiles can then be used to identify water zones or interfaces between oil and gas in each branch of a branched well. A device for positioning a tool in a wellbore and following a particular branch is known in the art.

[0057] Certain operations performed with the help of a coiled tubing use measurements of temperature differences along a wellbore or wellbore portion, as described by V. Jee et al., In US Patent Application 2004/0129418, the entire description of which is incorporated herein by reference. However, for other operations, the temperature at a particular location is interesting, e.g. the temperature at the bottom of the well. For such operations it is not necessary to obtain a full temperature profile along the fiber. Single-point temperature sensors have the advantage over temperature distribution measurements that the latter require signal averaging over a given time interval to remove noise. This may introduce a slight delay to surgery. When you need to change heads for fluid crushing (or the formation no longer accepts proppant), then the speed of obtaining information is of great importance. A single temperature or pressure sensor near the bottom of the well in the coiled tubing provides a mechanism for transmitting this important data to the surface quickly enough to allow control decisions to be made according to the state of the work.

[0058] In many applications of coiled tubing, it is desirable to know the location of the wellbore relative to the installed housing; a housing orifice locator that observes a size reference representative of the presence of a housing orifice is usually used for such location purposes. The traditional housing orifice locator has an electromagnetic coil wound axially around a tool in which voltage is generated in the coil in the presence of an alternating electric or magnetic field. Such a change occurs when moving the tool next to the housing part, which is characterized by a change in material properties, for example, in the case of a mechanical joint between two housing sections. Perforations and slip-on cylinders in the housing can also create signature voltages in the electromagnetic coil. Enclosure orifice locators need not be actively powered as described, for example, in US Patent 2,558,427, incorporated herein by reference. In certain example embodiments of this invention, a conventional housing orifice locator may be connected to optical fiber cable 211 via an electro-optical interface 503, using a light-emitting diode. To detect the position of the housing orifices in the wellbore, the housing orifice locator can be connected to the coiled tubing and transported along the wellbore. When the coiled tubing is moved, a signal is generated when changes in the electric or magnetic field occurring, for example, in the housing orifice and this signal is transmitted using fiber optic cable 211. Other methods of determining the depth include measuring a given size in the well and binding it sizes with previous measurements of the same size. For example, when drilling, it is common to measure the natural gamma radiation generated by the formation at each point along the wellbore. By providing optical fiber gamma measurement results, the depth of the coiled tubing can be determined by linking a given gamma radiation to an earlier measurement.

[0059] Borehole flow measurements are often desirable in coiled tubing operations, and embodiments of the present invention are useful for providing this information. Borehole flow measurements outside of the coiled tubing can be used to determine the formation fluid flow rate, for example, the rate of surgery, or the formation fluid flow rate, for example, the production rate or differential production rate. Flow measurements in a coiled tubing can be useful for measuring fluid delivery to different zones in a wellbore or for measuring the quality and consistency of foam in fluids for performing foam treatments. Known methods for measuring flow in a wellbore can be used with the present invention.

In some embodiments, a flow measurement device, e.g., a turbine, may be fiber optic 211. When a stream is connected, the device passes with the cable, the flow measuring device measures the flow rate and this measurement is transmitted by fiber optic cable 211. In the embodiments where it can be used A traditional flow measurement device that produces an electrical signal, an electric interface is provided

- optical 503, for converting electrical signals into optical signals, for transmission via fiber optic cable 211. A flow measurement device that uses a flow measurement turbine for direct optical measurement, e.g. by placing turbine blades between the light source and the photodetector such that the light it is alternately blocked and exposed when the turbine rotates, it can be used in some embodiments. Alternatively, flow measurement devices that utilize indirect optical techniques can be used in some embodiments of the present invention. Such indirect optical techniques are based on the influence of the flow rate on the optical device so that changes in the optical properties of the device can be observed, and can be used in some embodiments of the present invention.

[0060] It is often desirable to obtain information regarding the position or positioning of a tool or device in a wellbore in coiled tubing operations. In addition, it is desirable in coiled tubing operations to determine the state of a tool or device (e.g., open or closed, connected or disconnected) in a wellbore. The well path can be obtained from local tool position measurements or can be determined from continuous position monitoring when the tool is moved along the hole. The setting is useful for determining the position of a tool in a branched borehole because each branch has a known azimuth or slope against which the tool setting can be compared. Usually the tool position in the well is measured using a gyroscope, inertia sensor or accelerometer. For example, see US Patent 6,419,014, incorporated herein by reference. Such devices in fiber optic configurations are known. Fiber optic gyroscopes, for example, are available from many suppliers, such as Exalos, based in Zurich, Switzerland. In certain example embodiments of this invention, sensor 209 is a device for determining position or positioning of a tool, which is useful for determining the trajectory of a well. Such a position or positioning device can be connected to a fiber optic cable 211, the measurements taken are representative of the position or positioning in the wellbore and the measurement results are transmitted by fiber optic cable 211 in various embodiments of the present invention. In alternative embodiments, the sensor 209 may be a conventional or MEMS gyroscopic device connected to fiber optic cable 211 via an electro-optical interface 503.

[0061] The use of such positioning or positioning devices is particularly useful in branched wells. In certain example embodiments of this invention, a device for entering a given branch in a branched wellbore, e.g., as described in US Patent 6,349,768, incorporated herein by reference, can be used with a positioning or positioning device to determine first whether the tool or device is at the entrance to the branch.

In this way, the coiled tubing can be positioned in the required position within the wellbore, or the assembly of devices in the wellbore can be arranged in the required configuration. In addition, a mechanical or optical switch can be used to determine the position or condition of such a device assembly in the wellbore.

[0062] In some operations with coiled tubing information is needed regarding the solids content of the well, such as the height of the solid bed or the formation of deposits. In some embodiments of the present invention, sensor 209 is useful for measuring solids or detecting deposits during drilling operations. Such measurements can be transmitted via fiber optic cable 211. These measurements can be used to adjust a parameter such as the performance of a hydraulic pump or the speed of the coiled tubing to improve or optimize the operation of the coiled tubing. In some embodiments of the present invention, a conventional proximity sensor, including a conventional proximity sensor with an optical interface, or a gauge is used to determine the position and height of the solid bed in the well. Known proximity sensors use nuclear, ultrasonic or electromagnetic methods to detect the distance between the assembly at the bottom of the opening and the interior of the cladding. Such sensors can also be used to alert about impending screening during well operations such as fracturing. Detection of sediment formation is useful during wellbore operations to monitor the progress of wellbore work carried out during operations with coiled tubing, e.g. parent rock stimulation. In some embodiments of the present invention, the sensor 209 is a device for detecting deposit formation by methods known as direct optical measurement of reflection coefficient and scattering amplitude.

[0063] During wellbore operations, measurements of properties such as resistivity can generally be used as an indicator of the presence of hydrocarbons or other fluids in a formation. In some embodiments of the present invention, a tool or sensor 209 associated with an optical fiber cable 211 via an electro-optical interface can be used to measure resistivity using conventional techniques, as a result of which resistivity measurements are transmitted via an optical fiber cable. Alternatively, the resistivity can be measured indirectly by measuring the degree of salinity or refractive index using optical techniques, whereby the optical changes induced by the resistivity are then transmitted to the surface via fiber optic cable 211. In various embodiments, the present invention is useful for providing formation resistivity monitoring formation, working fluid or liquid, gas, solid or by-products.

[0064] In use in a wellbore, chemical analysis can be determined to some extent by means of a drilling sensor, such as luminescent sensors, fluorescent sensors or a combination of these resistivity sensors. Luminescent sensors and fluorescent sensors are known, as well as optical techniques for analyzing their output signals. One way to accomplish this is by measuring reflectance. When using a fiber optic sensor, light is supplied to the fluid and some of this light is reflected back to the sensor and correlated with the presence of gas in the fluid. A combination of fluorescent and reflective measurement can be used to determine the oil and gas content of a fluid. In some embodiments of the present invention, the sensor 209 is a luminescent or fluorescent sensor from which the output signal is transmitted via fiber optic cable 211. In specific embodiments where fiber optic cable 211 has more than one optical fiber, more than one sensor 209 may transmit information via separate optical fibers.

[0065] The presence of detection gases such as CO₂ and o₂ in the well, it can also be measured optically. Sensors for measuring such gases are known; see for example "Fiber Optic Fluorosensor for Oxygen and Carbon Dioxide"; Anal. Chem. 60, 2028-2030 (1988) by OS Wolfbeis, L. Weis, MJP Leiner and WE Ziegler, to which this publication refers. As described there, fiber optic performance enabling the simultaneous transfer of various optical signals can be used to build a fiber optic sensor for measuring oxygen and carbon dioxide. Oxygen sensitive material (e.g. fluorescent organometallic complex with absorbed silica gel) and CO sensitive material₂(e.g., an immobilized pH indicator in a buffer solution) can be placed in a gas-permeable polymer matrix attached to the distal end of the optical fiber. Although both of these indicators may have the same excitation wavelength (to avoid energy transfer) they have completely different emission maxima. Thus, these two emission bands can be separated by means of interference filters to provide independent signals.

Typically, oxygen can be determined in the range of 0 to 200 tracks with an accuracy of ± 1 track, and carbon dioxide can be determined in the range of 0-150 tracks with an accuracy of ± 1 track. Thus, in various embodiments of the present invention, the sensor 209 may be a CO detecting optical device₂ or O₂, where the measurement is transmitted via fiber optic cable 211.

[0066] pH measurement is useful in many operations with coiled tubing because the behavior of the working chemicals can strongly depend on the pH. PH measurement is also useful in determining fluid deposits. Fiber optic sensors for measuring pH are known. One such sensor described by MH Maher and MR Shahriari in Journal of Testing and Evaluation, Vol21, Issue 5 from Sep 1993 is a sensor constructed of a porous polymer film immobilized by means of a pH indicator placed in a porous sample. The optical spectral properties of this sensor show very good sensitivity to changes in pH levels tested with visible light (380 to 780 nm). Sol-gel sensors can also be used to measure the content of a specific chemical as well as for pH. Alternatively, the sensor can measure the pH by measuring the optical spectrum of the dye that has been injected into the fluid, as a result of which the dye has changed so that its spectral properties change depending on the pH of the fluid. Such dyes are similar in effect to litmus paper and are well known in the industry. For example, The Science Company of Denver, Colorado sells dyes that change color depending on narrow pH changes. The dye may be introduced into the fluid through a side leg 305 on the surface. In various embodiments of the present invention, the sensor 209 is a pH sensor connected to the fiber optic cable 211 so that the measurements from the sensor can be transmitted via an optical fiber cable.

[0067] It should be noted that detecting changes in pH changes is one example of how the present invention can be used to monitor changes in drilling fluids. It is believed that in the present invention, sensors useful for measuring changes in chemical, biological and physical parameters can be used as sensor 209, from which the measurement of the property or the measurement of the change in the property can be transmitted via fiber optic cable 211.

[0068] For example, the salinity of a wellbore fluid or pumped fluid can be measured or monitored by means of embodiments of the present invention. One method used in the present invention is to send a light signal through the optical fiber and detect the beam deflection caused by the optical refraction on the receiving end surface due to salinity of the brine. The measured optical signals are reflected and transmitted by a system of fibers arranged in a sequential manner, and then the peak light intensity and its deviation are detected using a load-coupled device. In this configuration, the sensor probe may consist of an intrinsically pure single GaAs crystal in the shape of a straight-angle pyramid, a septum water cell, an emission fiber with self-focusing lenses attached, and a linearly arranged array of receiving fibers. An alternative way of measuring salinity changes was proposed by O. Esteban, M. CruzNavarrete, N. lez-Cano, and E. Bernabeu in "Measurement of the Degree of Salinity of Water with a Fiber-Optic Sensor", Applied Optics, Volume 38, Issue 25, 5267-5271 September

1999, to which this publication refers. In the method described, a fiber optic sensor based on surface plasmon resonance is used to determine the refractive index and thus the salinity of the water. The transducer element comprises a multilayer structure mounted on one side polished optical fiber. Measurement of the attenuation of the power transmitted by the fiber indicates that a linear relationship with the refractive index of the external factor of the structure is obtained. The system is characterized by the fact that it uses a variable refractive index obtained with a mixture of water and ethylene glycol.

[0069] Embodiments of the present invention are useful for measuring fluid compressibility when the sensor 209 is such a device as described in US Patent 6,474,152, to which the present specification refers in its entirety, for measuring fluid compressibility and for transmitting the measurement via fiber optic cable 211. W such measurements avoid the need for measuring volumetric compressibility and are particularly suited for use with coiled tubing. In measuring the compressibility of a fluid, the change in optical absorption at certain wavelengths resulting from a change in pressure correlates directly with the compressibility of the fluid. In other words, applying a pressure change in a hydrocarbon fluid changes the amount of light absorbed by the fluid at certain wavelengths, which can be used as a direct indicator of fluid compressibility.

[0070] In various embodiments, the present invention provides a method of performing operations in underground wells comprising introducing cables fiber optic cable into the coiled tubing, inserting the coiled tubing into the well and performing at least one of the following steps: transmitting control signals from the control system via cable fiber optic for borehole equipment connected to a rolled pipe; transmitting information from wellbore equipment to the control system via fiber optic cable; or transmitting the property measured by the optical fiber cable to the control system via the optical fiber cable. In some embodiments, the present invention provides a method of conducting work in a wellbore including inserting an optical fiber cable into a coiled tubing, introducing a coiled tubing into a wellbore; and implementation of the operation; in which this operation is controlled by signals transmitted over a fiber optic cable. Such operations may include, for example, actuating valves, setting tools, activating a blasting head or perforating guns, activating tools, and switching valves. These examples are given as examples and not to impose restrictions.

[0071] In some embodiments of the present invention, drilling rigs, such as tools, can be optically controlled by signals transmitted via fiber optic cable 211. Similarly, information about a drilling rig, such as a tool kit, can be transmitted via fiber optic cable 211. In some embodiments, in which optical fiber cable 211 contains more than one optical fiber, at least one of the optical fibers can be allocated to tool communications. If necessary, more than one drilling device can be provided and a separate optical fiber can be allocated to each device. In other embodiments, in which a single optical fiber is provided in optical fiber cable 211, this communication may be duplicated so that the same fiber can also be used to carry detected information. If you have multiple tools, you can extend the duplication scheme such as multiple pulses at a time, constant pulse length, incident light intensity, incident wavelength, and binary commands to include additional tools.

[0072] In some embodiments of the present invention, a valve actuator device, a fiber optic drilling rig, such as a mechanism is provided in conjunction with the purpose of forming an optical actuated valve. The fiber interface is connected to the fiber optic cable 211 so that control signals can be transmitted to the device via fiber optic cable 211. One embodiment of the fiber interface can include an optical-electrical interface coupler with a small battery for converting the optical signal into a small electrical signal that activates the solenoid, which in turn actuates the valve.

[0073] Typically in coiled tubing operations, drilling tools are configured on the surface before entering the wellbore. However, there are situations in which it would be desirable to set or adjust the position of the drilling tool. In some embodiments of the present invention, the drilling tool is provided with an optical-electrical interface for receiving optical signals and converting the optical signals into electrical or digital signals. The optical-electrical interface is further connected to the logic in the drilling tool to load and possibly store in memory the parameters of the tool or sensor. Thus, the optical fiber enabling coiled tubing operations with a tool equipped to receive tool parameters on fiber optic cable 211 provides the operator with the ability to adjust tool settings in the well in real time.

[0074] One example is the adjustment of the collar reinforcement of the optical fiber casing pipe collar. In this case, one gain setting may be desirable to run operations at 50 to 100 feet per minute (0.254 to 0.508 m / s), and another gain setting may be desirable for recording or perforating operations at 10 feet per minute (0 , 0508 m / s) or less. The control signal from surface devices can be transmitted to the casing flange locator via fiber optic cable 211. This functionality is useful because different gain settings based on specific casing metallurgy may be desired. This metallurgy may not be known in advance and, as a result, it may be desirable to send a control signal from the surface device to the casing flange locator via fiber optic cable 211 to adjust the gain setting in real time in response to the measurement made by the casing flange locator and transmitted to surface equipment via fiber optic cable 211.

[0075] In other embodiments, the present invention provides a method of firing a perforation gun or blasting heads in a wellbore by transmitting a control signal from the surface device to the drilling rig. The fiber interface can be used with a shot head actuated by electrical signals, the fiber interface converting the optical signal transmitted via fiber optic cable 211 to an electric signal for firing the shot head. A small battery may be used to power this interface. More than one blasting head can be used. In embodiments where fiber optic cable 211 contains more than one optical fiber, each head may be allocated to a unique fiber. Alternatively, if a single optical fiber is provided, a unique code sequence may be used to provide discrete signals to different shot heads. The use of optical fiber for the transmission of such control signals is advantageous in that it minimizes the possibility of accidental firing of the wrong head due to electromagnetic crossing, such as can be seen in a wired cable. Alternatively, a light source from the surface can be used to directly activate the explosive shothead. In some embodiments, the shot head can be actuated by means of an optical control circuit such as that described in US Patent 4,859,054 to which the present specification refers.

[0076] During the operation with coiled tubing, it is often necessary to run the tools in

Starting the tool can take on a variety of things such as, but not limited to, energy release, displacement of the safety or locking element, actuation of the clutch, actuation of the valve, actuation of the shothead for perforation. Such actuation is typically controlled or verified by means of elemental telemetry, on which the well bore, stored connected, sent consists of pressure, flow rate and push / pull forces that are susceptible to well bore interaction, and can often be ineffective. For example, push / pull forces exerted on the surface are reduced by friction with the wellbore, the amount of friction being unknown. When using pressure communication, the signal is often masked by the friction pressure associated with the fluid circulating in the coiled tubing and the flow in the wellbore. Flow rate is typically a better means of communication; however, some tools require a configuration that leads to unknown fluid leaks that can affect the flow rate indicator. In some embodiments, the tool actuation signals are transmitted to the tool via fiber optic cable 211. In some cases, the tool may be equipped with an optical-electrical interface, which may have an amplifying circuit and the ability to receive the optical signal and convert it into an electrical signal to which the tool actuating circuit responds, while in other cases, the tool may be adapted to receive the signal directly supply.

[0077] In one embodiment of the invention, the optically controlled reversing valve is with a fiber optic cable. The signal may be to the reversing valve from the surface control device 119 through the fiber optic cable 211 to disable the check valves, e.g. to allow reverse fluid circulation of the ring to the coiled tubing) In response to this signal, the valve (i.e. conditions.

passes the off position to activate the check valves. In an embodiment, actuating the reversing valve with optical fiber may further provide a signal from the valve to the surface device to indicate the status of the valve.

[0078] In various embodiments, the present invention provides a method of treating a subterranean well-cut formation, which method includes inserting an optical fiber cable into the coiled tubing, introducing the coiled tubing into a wellbore, performing a well treatment operation, measuring the properties in the well and using a cable fiber optic for transferring the measured property. The fiber optic coiled cord device 200 can be used to perform well processing, well intervention and well management, and enables operations that are hitherto not possible using a conventional coiled cord device. It should be noted that a key advantage of the present invention is that fiber optic cable 211 does not prevent the use of a coiled tubing chain for machining operations. Furthermore, since many machining operations in the well require moving the coiled tubing in the wellbore, for example to "flush" acid along the inside of the wellbore, the advantage of this invention is that it is adapted for use because the coiled tubing moves in the wellbore.

[0079] Stimulation of the parent rock is an orifice operation in which fluid, typically acidic, is injected into the formation through a pumping operation. The coiled tubing is useful in parent rock stimulation because it allows concentrated injection of the working fluid into the desired zone.

Stimulation of the parent rock may involve injection of multiple feed fluids into the formation. In many applications, the first pre-flushing fluid is pumped to remove any material that could cause deposition, and then the second fluid is pumped as soon as the area near the well is cleaned. Alternatively, the parent rock stimulation operation may involve injection of a mixture of fluids and solid chemicals.

[0080] Referring to Figure 6, it shows a schematic illustration of parent rock stimulation implemented using a coiled tubing device comprising a fiber optic cable according to the invention, in which the fluid for treating the hole is introduced into the wellbore 600 through the coiled tubing 601. The working fluid may be introduced using one of the various tools known in the art for this purpose, for example, nozzles attached to a rolled tubing. In the example of Figure 6, fluid that is introduced into the wellbore 600 is prevented from escaping from the treatment zone by means of partitions 603 and 605. Partitions 603 and 605 may be some sort of mechanical partition, such as an inflatable sealant or chemical compartment, such as a cushion or foam partition.

[0081] In parent rock stimulation operations, it is preferable to place cutting fluid in the correct zone (s) in the wellbore 600. In a preferred embodiment, an optical sensor 607 capable of determining depth may be used to determine the location of the drilling apparatus supplying the fluid to stimulate the parent rock. The optical sensor 607 is connected to a fiber optic cable 211 to communicate the location in the wellbore 600 to the surface control device, allowing the operator to initiate the introduction of machining fluid to the optimal location.

[0082] The present invention allows real-time monitoring of parameters of such bottom pressure, bottom temperature, bottom pH, amount of sediments formed as a result of interaction of cutting fluids and formations, and fluid temperature, each of which is useful for monitoring the success of parent rock stimulation operations. A sensor 609 for measuring such parameters (e.g., a sensor for measuring pressure, temperature, or pH, or for detecting deposits) may be connected to a fiber optic cable 211 located inside the coiled tubing 601 and a fiber optic cable 211. Then these measurements can be passed to surface equipment via fiber optic cable 211.

desired stimulation [0083] For example, real-time bottom pressure measurement is useful for monitoring and evaluating formation coatings, which allows optimization of stimulation fluid injection performance, or allows regulation of the concentration or relative mixing ratio of fluid or relative mixing ratio of fluids and solid chemicals. When the coiled tubing is moving, real-time bottom pressure measurements can be adjusted by subtracting tampon and impact effects to account for the movement of the coiled tubing. Another real-time use of bottom pressure is to keep bottom pressure from pumping fluid below the threshold level. For example, during parent rock contact of the wellbore surface with cutting fluid is important. If the well pressure is too high, the formation will crack and the treatment fluid will break, which is not desirable. The ability to measure bottom pressure in real time is particularly useful when foaming cutting fluids. When pumping non-foamed fluids, bottom pressure can sometimes be determined from surface measurements by adopting some formulas for friction losses in the wellbore, but such methods are not well established for use with foamed fluids.

[0084] Measurements of bottom parameters other than pressure are also useful during well treatment operations. Real-time bottom temperature measurements can be used to calculate foam and are therefore useful to ensure the effective use of bleed techniques. Similarly, bottom temperature can be useful in determining the progress of stimulation surgery and is therefore useful in regulating the concentration or relative proportions of mixing liquids and solid chemicals. Bottom pH measurement is useful for choosing the optimal concentration of cutting fluids or the relative proportions of each pumped fluid or the relative mixing ratios of fluids and solid chemicals. Measurement of sludge formed by the interaction of fluids with the wellbore wall can also be used to analyze the need to adjust the concentration or mixture of cutting fluid, for example, relative concentrations or relative mixing ratios of fluids and solid chemicals.

In an alternative application of the coiled tubing device 200, in which a plurality of fluids are injected into the formation, partly through the coiled tubing and partly through the ring formed between the coiled tubing 105 and the wellbore wall 121, the coiled tubing 105 forms a mechanical septum, or they can transition transient isolating fluids injected through the coiled tubing 105 from fluids injected into the ring. Measurements, such as bottom temperature and bottom pressure, carried out in real time and transmitted to the surface via fiber optic cable 211 can be used to adjust the relative proportions of fluids injected through the coiled tubing 105 and fluids injected into the ring.

[0086] In one alternative, the coiled tubing 105 acts as a fluid barrier between the coiled tubing 105 and the ring, fluids injected through the coiled tubing 105 are foamed or aerated. When flowing out of the bottom hole at the end of the coiled tubing 105, the foamed fluids partially fill the annular space around the base of the coiled tubing, thereby forming a transition surface in the ring between fluids pumped down the coiled tubing and fluids pumped through the ring. It is possible to regulate various parameters of stimulation operations, including the relative proportions of fluid pumped to the ring and to the coiled tubing, and the position of the coiled tubing to ensure that the transition surface is at a particularly desirable location in the tank to be used to locate the surface

Adjusting the specific surface position is useful to ensure that stimulant fluids enter the tank of interest in the tank, either to intensify the flow of hydrocarbons from the tank or to inhibit the flow from the hydrocarbon-free zone. To intensify the flow of hydrocarbons by inhibiting the flow of non-hydrocarbons, a separating fluid can be pumped into the coiled tubing as described in US Patent

6,667,280, to which this description refers in full.

[0087] In some parent rock stimulation operations, it may be desirable to pump the catalyst into coiled tubing 105 to transfer the catalyst to a specific location in the wellbore. Physical properties, such as bottom temperature, bottom pressure, and bottom pH, which are measured and transmitted to the surface in real time via fiber optic cable 211 can be used to monitor the progress of the parent rock stimulation process and, consequently, to adjust the catalyst concentration to influence this progress. In some embodiments of the invention, in parent rock stimulation operations, an optical fiber cable can be used to provide a temperature distribution profile such as that described in US Patent Publication 2004/0129418.

[0088] In another well treatment operation, the optical fiber actuated coiled tubing device 200 of the present invention is used in a fracturing operation. Fracturing with a coiled tubing is a stimulating treatment in which slurry or acid under pressure is injected into the formation. Fracturing operations benefit from the possibilities of the present invention by using fiber optic cable for real-time data transmission in several ways. First, real-time information such as bottom pressure and bottom temperature is useful for monitoring the progress of machining in the well and for optimizing the fracturing fluid mixture. Often, fracturing fluids, especially polymeric fracturing fluids, require a crushing additive to crush the polymer. The time required to crush the polymer depends on the temperature, operating time and concentration of the fracturing agent. Consequently, the knowledge of the bottom temperature enables the fracturing schedule to be optimized to crush fluid when it enters the formation or immediately thereafter, which reduces contact between polymer and formation. The introduction of a polymer intensifies the fluid's ability to protect the fracturing material (e.g. sand) used in the fracturing operation.

[0089] In addition, pressure sensors can be inserted into the coiled tubing to allow assessment of fracturing development characteristics. In this industry, the Nolte-Smith graph is used to evaluate the development of machining, which is a logarithmic graph of pressure versus time. The formation's inability to accept even more sand can be detected by the increase in the curve slope (pressure) as a function of (time). With this information in real time using the present invention, it would be possible to adjust the performance and concentration of fluid and fracturing fluid on the surface and manipulate the coiled tubing in such a way as to actuate the drill valve mechanism to flush the fracturing fluid from the coiled tubing. One such drilling valve mechanism is described in Patent Publication US 2004/0084190, to which the present description refers in its entirety. A drilling pressure sensor can be attached to fiber optic cable 211 so that pressure measurements can be transmitted to a surface device to provide well surface treatment information. In addition, measurements from drilling pressure sensors connected to a fiber optic cable 211 can be used to identify the start of screening treatment where the treated subterranean formation no longer receives treatment fluid. This condition is typically preceded by a gradual increase in pressure on the NolteSmith chart, where such a gradual increase is typically not identifiable only by surface pressure measurements. Consequently, the present invention provides useful information to identify a gradual increase in pressure, enabling the operator to adjust treatment parameters such as sand yield and concentration to avoid or minimize the effect of the screening condition.

[0090] In general, proper placement of treatment fluids in specific underground formations is important. In one alternative embodiment of the invention, the sensor 607 is a sensor capable of determining the location of the device with a coiled tubing in the opening 600 and furthermore capable of transmitting the required data indicating the location of the fiber optic cable 211. The sensor may be, for example, a shield flange locator (CCL) . By real-time transmission to the surface control unit 110, the depth of the coiled tubing, the conveyed fracturing tools to the surface device, it is possible to ensure that the fracturing depth corresponds to the desired zone or perforated compartment.

[0091] Filling cleaning is another drilling operation in which coiled tubing is often used. The present invention provides advantages in cleaning the fill by providing information such as the height of the filled bed and the concentration of sand in the flushing nozzle in real time through fiber optic cable 211. According to an embodiment of the invention, this operation can be intensified by providing a drilling measurement of the compression of the coiled tubing, since this concentration increases when the end of the coiled tubing is pushed further into the hard filling. According to some embodiments of the present invention, the drilling sensor operatively measures fluid properties and bore parameters that affect fluid properties and communicates these properties to the surface device via fiber optic cable 211. Fluid properties and associated parameters that are desirable to measure during surgery fill cleaning include, but is not limited to, viscosity and temperature. Monitoring of these chemical composition optimization properties used in fill cleaning operations. According to yet another embodiment of the invention, the optically actuated coiled cord device 200 can be used to provide cleaning parameters such as those described in the US Patent Application "Device and Methods for Measuring Solids in a Well" filed by Rolovic et al., US Patent Application No. 11 / 010,116, to which this description refers in full.

may be used for or mixing fluids [0092] Referring now to Figure 7, it shows a schematic illustration of an intensified fill operation by using an actuated rolled cord chain equipped with an optical fiber according to the invention. Coiled tubing 601 can be used to transfer the flushing fluid to orifice 600 and used to fill 703. The drill end of the coiled tubing may be provided with some type of nozzle 701. Sensor 705 is connected to fiber optic cable 211. Sensor 705 can measure any various properties that may be useful in fill cleaning operations, including coil compression, pressure, temperature, viscosity and density. These properties are then transferred via fiber optic cable 211 to the surface device for further analysis and possible optimization of the cleaning process.

[0093] In an alternative embodiment, the nozzle 701 may be equipped with a plurality of controlled windows. During cleaning, the nozzle may be clogged or jammed. By selectively opening multiple controlled windows, the nozzle can be cleaned by selectively flushing the controlled windows. During such operations, an optical fiber cable is used to transfer control signals from the surface device to the nozzle 701 to control the nozzle such that the selective rinsing of one or more controlled windows occurs. The optical signal can run controlled windows using an electric actuator, powered by a battery, to run each controlled window, this optical signal is used to control the electric actuator. Alternatively, these actuators may be light actuated valves in which the optical energy sent by the fiber powers the valve, causing, in particular, the resultant action to selectively open or close one or more controlled windows.

[0094] In some embodiments of the present invention, the tool or sensor 607 of the coiled tubing device 200 having an optical fiber may include a camera or a detector system used to remove sediment stone. The settling stone can settle inside the production pipeline and then acts as an obstacle, thereby reducing bore efficiency and / or increasing mining costs. A camera or detector system connected to a 211 fiber optic cable can be used to detect the presence of sediment stone in the production pipeline. Photographic images, in the case of a camera, or data indicating the presence of sedimentary stone, in the case of a sensor system, can be transmitted via fiber optic cable 211 from the camera in the borehole or from the sensor system to the surface where they can be analyzed.

[0095] In another alternative, the tools or sensor 607 may include a fiber operated valve. The fiber-controlled valve is connected to the 211 fiber-optic cable and, in response to control signals from the surface device, this valve can be used to mix or release chemicals to remove or inhibit sedimentation.

[0096] In operations with coiled tubing, such as, for example, stimulation, water control and testing, it is often desirable to isolate a particular open zone in the wellbore to ensure that all pumped or generated fluid flows out of the given isolated zone. In an embodiment of the invention, the coiled tubing device 200 equipped with an optical fiber is used to activate a zonal control device. Fiber optic cable 211 allows the operator to apply a surface device to the zonal control device more precisely than a shut-off device by using push-pull commands and hydraulic commands known to date. Zonal shut-off operations can also use real-time information on available pressure, temperature and location (e.g. from CCL).

[0097] By using optical fiber communication along optical fiber cable 211, the implementation of zonal cut-off operations and measurements is significantly improved because the communication system does not interfere with the use of a coiled tubing for pumping fluid. In addition, by reducing the intensity of pumping required, operators using optical fiber communication for zonal cut-off, as described herein, can expect financial and time savings.

[0098] Embodiments of the present invention are useful for perforating using a coiled tubing. When perforating, it is critical to have good depth control. Depth control in operations with a coiled tubing can be difficult, however, due to residual bending and a tortuous motion path, the coiled tubing enters the wellbore. In the current technique of perforating operations by means of a transferable coiled tubing, the depth at which shot heads with hydraulic drive are fired is controlled by a series of memory operations in connection with a stress prediction program or a separate measuring device. A memory-based approach is both expensive and time consuming, and using a separate device can increase time and labor costs.

[0099] Figure 8 is a schematic illustration of a perforating device carried by the coiled tubing according to the present invention, wherein the coiled tubing device 200 equipped with optical fibers is perforated. The locator for the implementation of the sheath is adapted flange 801 attached to the coiled tubing 601 and connected to the fiber optic cable 211. A perforating tool 803, such as a shot head, is also attached to the coiled tubing. The shield flange locator 801 transmits signals indicating the position of the shield flange via an optical fiber cable to the surface device. The perforating tool 803 also connected to the fiber optic cable directly or indirectly, as a result of which it can be actuated by transmitting optical signals from the surface device via fiber optic cable 211 when at the desired depth, measured by the shield flange locator.

may be 211, or [0100] Referring now to Figure 9, it is shown an exemplary illustration of a bottom flow controller in which a fiber optic control valve 901 or 901 'can be used to control fluid flow to the well and reservoir. For example, control valve 901 may be used to either direct the pumped fluid from the coiled tubing to the tank, or control valve 901 'may be used to direct the return flow to the ring surrounding the coiled tubing 601. This technique is often called "spotting" and is useful in situations where the proper volume of this fluid stimulates the reservoir, but too much of this fluid could actually damage production from underground formation. In some embodiments, the present invention includes a specific flow control mechanism comprising a light sensitive sensor coupled to an amplifier circuit 903 or 903 'for receiving a light signal and converting the light into an electrical voltage or current source, which in turn drives the valve actuator 901 or 901 '. A small energy source can be used to drive the 903 or 903 'electric boost circuit.

with a retractable handling such as a sleeve [0101] One joint operation behind the pipe is used with drilling, supplementary, sliding equipment. Typically, this is accomplished by running a specially constructed tool that latches onto the complementary element then manipulated with the coiled tubing which results in manipulation of the useful element

The present invention is selectively manipulating more waveform. cleansing than one

For example, the hole and the complementary. to allow or allow tampering during one if the operator needs to run the complementary component, he may use fiber optic cable 211 to send control signals to control system 119 to selectively change from a cleaning configuration to a manipulative configuration. Similarly, the present invention can be used to verify the status or location of a device in a wellbore while carrying out unrelated intervention.

[0102] Another operation in the opening during which the coiled tubing is used is to catch the device lost in the wells. The trapping operation typically requires hooking a special size jaw or rod into the uppermost element remaining in the wellbore, the uppermost element being called a latch. In some embodiments, the tool or sensor 209 is a sensor connected to a fiber optic cable and capable of verifying whether a latch is hooked in the searching tool. This sensor is, for example, a mechanical or electrical device that senses the correct hooking of the hook. This sensor is connected to an optical interface for processing the detection of a properly hooked hook into an optical signal transmitted to the surface device via fiber optic cable 211. In another embodiment, the tool or sensor 209 may be an imaging device (e.g., a camera such as that available from DHV International of Oxnard, California) connected to a fiber optic cable and able to accurately determine the dimensions and shape of the hitch. The images obtained by the imaging device are transmitted to the surface device via fiber optic cable 211. In other embodiments, the adjustable search tool can be connected to the fiber optic cable 211 so that the search tool can be controlled from the surface device by transmitting optical signals through fiber optic cable 211, which allows a significant reduction in the number of search tools needed. In this embodiment, the tool or sensor 209 is an optically actuated device similar to the optically actuated valves and windows discussed above.

[0103] In some embodiments, the present invention relates to a method of introducing a borehole or determining properties in a wellbore comprising inserting an optical fiber cable into a coiled tubing, inserting a measuring tool into a wellbore on a coiled tubing, measuring properties using a measuring tool and using a fiber optic cable for transfer of the measured property. The coiled tubing and measuring tool can be pulled out of the wellbore and it is possible to make measurements during extraction, or it is possible to make measurements concurrently with the execution of machining operations. The measured properties can be transferred to the surface device in real time.

[0104] When introducing a wire conductor, one or more electrical sensors (e.g., one that measures formation resistivity) are combined into a tool known as a probe. This probe is lowered into a borehole on an electric cable and then pulled out of the borehole with simultaneous collection of measurements. The electric cable is used to supply power to the probe and to telemetry the collected data. Measurements were also made in the hole using a device with a coiled tubing in which an electric cable was installed in the coiled tubing. An advantage of the coiled tubing device according to the present invention is that fiber optic cable 211 is more easily inserted into the coiled tubing than the electric conduit. In the application of a fiber optic coiled tubing device embedded in an opening, tools or sensors 209 are a measuring device for measuring physical properties in a well or rock surrounding a reservoir. In applications where the tool or sensor 209 requires power for recording or measuring, such power can be provided by means of a battery pack or turbine. However, in some applications this means that the size and complexity of the surface feed can be reduced.

[0105] Although specific embodiments of the invention have been described and illustrated herein, the invention is not limited to the specific forms or arrangement of parts described and illustrated. Many variants and modifications are obvious to people with relevant skills in this field after fully reading the above description. The present invention should be interpreted as including all such variations and modifications.

Schlumberger Technology BV Representative:

EP 1 753 934 B1