RU2565299C2 - Drilling with pressure optimisation by continuous drilling string of lifting pipes - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: invention relates to the method for drilling of a well shaft. The method includes drilling of a well shaft by means of a continuous drilling string of lifting pipes, measurement of at least one parameter by means of an optical wave guide in a drilling string, besides, measurement includes a stage, when they determine optical back scatter along the optical wave guide, and nozzle adjustment, thus causing fluid inflow into the well shaft or fluid loss from the well shaft, at the same time measurement of at least one parameter additionally includes a stage, when they determine fluid inflow or loss.

EFFECT: increased efficiency.

26 cl, 8 dwg

Description

FIELD OF THE INVENTION

The present invention relates essentially to the equipment used and the operations performed in well drilling, and in the embodiment described herein, in particular, pressure optimized drilling of a continuous drill string of tubing is provided.

BACKGROUND

In conventional drilling operations, surface sensors and the bottom of the drill string can be used to determine various parameters that affect drilling operations. However, such sensors do not measure parameters along the drill string and have limited applicability in determining fluid inflow into a wellbore, or in determining fluid loss from a wellbore.

Therefore, it should be understood that improvements are required in the technique of measuring parameters in drilling operations. These improvements may be useful in the above and other situations.

BRIEF DESCRIPTION OF THE DRAWINGS

In FIG. 1 is a partial cross-sectional view of a borehole system and corresponding method for implementing the present invention.

In FIG. 2 shows a block diagram of a process control system that can be used with the well system and method of FIG. one.

In FIG. 3 shows another configuration of a downhole system.

In FIG. 4 shows an enlarged local section of the borehole system.

In FIG. 5 is a graph of temperature versus depth in a wellbore, wherein the graph contains an indication of fluid loss from the wellbore.

In FIG. Figure 6 shows a graph of temperature versus depth along the wellbore; the graph contains an indication of fluid flow into the wellbore.

In FIG. 7 is a flowchart of a method for determining inflow and responsive control of a fitting in an embodiment of the present invention.

In FIG. 8 is a flowchart of a method for determining fluid loss and responsive control of a fitting in an embodiment of the present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS OF THE INVENTION

In FIG. 1 shows a borehole system 10 and a corresponding embodiment of the present invention. In system 10, the wellbore 12 is drilled with a rotating drill bit 14 at the end of the tubing string 16. The drilling fluid 18 is usually circulated through the drill string 16 downstream of the drill bit 14 and up through the annular space 20 formed between the drilling the column and barrel 12 of the well, for cooling the drill bit, lubricating the drill string, removing drill cuttings and providing pressure control at the bottom of the well. The non-return valve 21 (generally a check valve type check valve) prevents upward passage of the drilling fluid 18 through the drill string 16.

Pressure control in the bottomhole zone of a well is very important in drilling under controlled pressure, in depression drilling and in drilling with optimization of other types of pressure. Preferably, the pressure in the bottomhole zone of the well is optimized to prevent excessive fluid loss into the formation 64 of the rock surrounding the wellbore 12, abnormal hydraulic fracturing, abnormal flow of formation fluid into the wellbore, etc.

In conventional drilling under controlled pressure, it is required to maintain the pressure in the bottomhole zone of the well above the pore pressure of the formation 64, but below the pressure of the hydraulic fracturing. In conventional depression drilling, it is required to maintain the pressure in the bottomhole zone of the well slightly below the pore pressure, while obtaining a controlled flow of fluid from the formation 64.

Nitrogen or another gas or other lighter fluid may be added to the drilling fluid 18 to control pressure. This technique is particularly useful, for example, in drilling on a depression, or drilling under controlled pressure with a divided density (for example, with a double gradient).

In system 10, additional pressure control in the bottomhole zone of the well is obtained by isolating the annulus 20 (for example, isolating it from the atmosphere and sealing the annulus on or near the surface) using a rotary control device 22 (RCD). The rotary control device 22 is sealed on the drill string 16 above the wellhead equipment 24. Although not shown in FIG. 1, the drill string 16 must extend upward through a rotary control device 22 for connecting, for example, to the riser line 26 and / or other conventional drilling equipment.

The drilling fluid 18 exits the wellhead equipment 24 through a slide gate valve 28 communicating with the annular space 20 below the rotary control device 22. The fluid 18 then flows through the fluid return line 30 to the choke manifold 32, which includes duplicated nozzles 34. The backpressure is applied to the annular space 20 by changing the throttling of the fluid stream 18 through the working (working) duplicated fitting 34.

The greater the throttling of the flow through the fitting (fitting) 34, the greater the back pressure applied to the annular space 20 for a given flow rate. Thus, the pressure in the bottomhole zone of the well can be successfully controlled by changing the back pressure applied to the annular space 20, changing the throttling of the flow through the nozzle (fitting) 34. You can use the model of the hydraulic system described more fully below to determine the pressure applied to the annular space 20 on or near the surface, the specified pressure should ensure the creation of the required pressure in the bottomhole zone of the well, so that the operator (or automated system is controlled I) may readily determine the pressure control method applied to the annulus at or near the surface (that can be successfully measured) to obtain a desired pressure downhole wellbore zone.

Pressure control at other locations along the wellbore 12 may also be required. For example, pressure on a shoe of a casing string, on a heel of a lateral wellbore, generally in vertical or horizontal portions of a wellbore 12, or anywhere else can be controlled using the principles of the present invention.

The pressure applied to the annular space 20 can be measured on or near the surface by means of various pressure sensors 36, 38, 40, each of which communicates with the annular space. A pressure sensor 36 measures pressure below the rotary control device 22, but above the blowout preventer block 42. A pressure sensor 38 measures the pressure in the wellhead equipment below the blowout preventer unit 42. The pressure sensor 40 measures the pressure in the return line 30 of the fluid upstream of the nozzle manifold 32.

Another pressure sensor 44 measures the pressure in the riser line 26. Another pressure sensor 46 measures pressure downstream of the nozzle manifold 32, but upstream from the separator 48, the vibrating screen 50 and the drilling fluid reservoir 52. Additional sensors include temperature sensors 54, 56, Coriollis flowmeter 58, and flowmeters 62, 66.

Not all of these sensors are required. For example, the system 10 may include only one of the flowmeters 62, 66. However, the input from the sensors is needed for the model of the hydraulic system to determine the pressure that must be applied to the annular space 20 during drilling.

In addition, the drill string 16 may include its own sensors 60, for example, for direct measurement of pressure in the bottomhole zone of the well. Such sensors 60 may be well-known to those skilled in the art sensors for measuring pressure while drilling (PWD), measurements while drilling (MWD) and / or logging while drilling (LWD). Said drill string sensor systems provide at least a pressure measurement and can also provide temperature measurement, determination of drill string operating parameters (such as vibration, axial load on the bit, sticking and slipping, etc.), formation parameters (such as resistivity , density, etc.) and / or other measurements. Various forms of telemetry (acoustic, by pressure pulses, electromagnetic, optical, wire, etc.) can be used to transmit measurements of downhole sensors to the surface. The drill string 16 can be equipped with electric wires, optical waveguides, etc. for transmitting data and / or commands between the sensors 60 and the process control system 74 described below (see FIG. 2).

Additional sensors can be included in system 10, if required. For example, another flowmeter 67 can be used to measure the flow of fluid 18 exiting the wellhead equipment 24, another Coriolis flowmeter (not shown) can be connected directly upstream or downstream of the mud pump 68, etc.

Fewer sensors can be included in system 10, if required. For example, the output of the mud pump 68 can be determined by counting the strokes of the pump, instead of using a flow meter 62 or any other flow meter.

It should be noted that the separator 48 may be a three or four phase separator, or a gas separator of a drilling fluid (sometimes called a “degasser”). However, the separator 48 is not necessarily used in the system 10.

The drilling fluid 18 is pumped through the riser line 26 and into the inner volume of the drill string 16 by the mud pump 68. The pump 68 receives fluid 18 from the mud tanks 52 and delivers the riser through the manifold 86 (not shown in FIG. 1, see FIG. 3) to line 26 riser. Then, the fluid 18 is circulated downward through the drill string 16, upward through the annular space 20, through the return line 30 of the drilling fluid, through the choke manifold 32 and then through the separator 48 and the vibrating screen 50 into the drilling fluid reservoir 52 to bring the required condition and recirculation.

It should be noted that in the system 10 described above, the nozzle 34 cannot be used to control the back pressure applied to the annular space 20 to control the pressure in the bottomhole zone of the well if the fluid 18 does not flow through the nozzle. In conventional repression drilling, a cessation of circulation can occur when a connection is made in the drill string 16 (for example, to build up the drill pipe links in the drill string as the wellbore 12 deepens), and the cessation of circulation requires pressure regulation in the bottomhole zone of the well only using fluid density 18.

In the system 10, however, the flow of fluid 18 through the nozzle 34 can be maintained even if there is no fluid circulation through the drill string 16 and the annular space 20. Thus, the application of pressure to the annular space 20 can continue by throttling the flow of fluid 18 through the nozzle 34 This feature may be useful, for example, when lowering / raising drill string 16 into the wellbore and from the wellbore 12.

In the system 10, as shown in FIG. 1, a backpressure pump 70 can be used to supply fluid to the return line 30 upstream of the nozzle manifold 32 and pumping fluid into the annular space 20 or other place upstream of the nozzle manifold. As shown in FIG. 1, the pump 70 is connected to the annular space 20 through a blowout preventer block 42, but in other examples, the pump 70 can be connected to the return line 30 or to the choke manifold 32.

Alternatively or in addition, fluid may be diverted from the riser manifold (or otherwise from the mud pump 68) to return line 30 when required, as described in PCT application US08 / 87686, in US application 13 / 022,964, or using other techniques.

Throttling the fitting 34 of such a fluid stream from the mud pump 68 and / or the back pressure pump 70 should provide pressure to the annular space 20. If a back pressure pump 70 is used, the flow meter 72 can be used to measure pump performance.

The fitting 34 and the backpressure pump 70 are examples of pressure control devices that can be used to control pressure in the annular space 20 near the surface. Other types of pressure control devices (such as those described in PCT / US08 / 87686, and US 13 / 022,964, etc.) can be used if required.

In FIG. 2 is a block diagram of one example of a process control system 74. In other examples, the control system 74 may include other quantities, types, combinations, etc. of elements, and any elements may be installed in various places or integrated with another element, within the scope of the present invention.

As shown in FIG. 2, the control system 74 includes a data acquisition and control interface 118, a hydraulic system model 120, a predictive device 122, a data validation unit 124 and a controller 126. These elements may be similar to those described in international application PCT / US10 / 56433, published 12 November 2010

The hydraulic system model 120 is used to determine the required pressure in the annular space 20 to obtain the required pressure at a specific location in the wellbore 12. The hydraulic system model 120, using data such as borehole depth, drill string rotation speed, descent rate, type of drilling fluid, etc., simulates the borehole 12, drill string 16, fluid flow through the drill string and annulus 20 ( including equivalent circulation density due to such a flow), etc.

The data acquisition and control interface 118 receives data from various sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 66, 67, 72, together with the rig data and well data, and transmits the indicated data into a hydraulic system model 120 and a data validation unit 124. In addition, the interface 118 transmits the required annular pressure data from the hydraulic system model 120 to the data validation unit 124.

Predictive device 122 can be included in the specified example to determine, based on statistical data, which sensors should be received at the moment and what pressure is required in the annular space. Predictive device 122 may include a neural network, a genetic algorithm, fuzzy logic, etc., or any combination of predictive elements to obtain predictions of sensor data and the required pressure in the annular space.

The data validation unit 124 uses these predictions to determine the validity of any specific sensor data, the acceptability of the required pressure in the annular space provided by the hydraulic system model 120, etc. If the above is acceptable, the data validation unit 124 transmits the required pressure in the annular space to the controller 126 (such as a programmable logic controller, which may include a proportional-integral-differential controller (PID controller)) that controls the operation of the fitting 34, pump 70, and various flow control devices 128 (such as valves, etc.).

Thus, the fitting 34, the pump 70, and the flow control device 128 can be automatically controlled to obtain and maintain the required pressure in the annular space 20. The actual pressure in the annular space 20 is usually measured at or near the wellhead equipment 24 (for example, using sensors 36, 38 , 40), which can be located on a land or underwater site.

In FIG. 3 schematically shows another configuration of a well drilling system 10. In this configuration, the flow control device 76 is connected upstream of the rig riser manifold 86. A flow control device 76 can be connected between the mud pump 68 and the riser manifold 86 using, for example, quick couplers 84 (such as a thread nut, etc.). The above should provide the device 76 flow control ease of connection to the pump lines of various drilling rigs.

A specially adapted fully automated flow control device 76 (for example, one of the flow control devices 128 controlled by an automatic controller 126) can be used to control the flow in the riser line 26, instead of using a conventional valve in the riser of the riser rig 86. The flow control device 76, together with one or more additional flow control devices 78, 80, 82, can be used to divert the fluid stream 18 from the mud pump (s) 68 to the choke manifold 32 along the bypass line 75.

In FIG. 4 shows an additional configuration of the borehole system 10. In this configuration, the drill string 16 comprises a flexible tubing or other continuous tubing that has at least one optical waveguide 88 (such as an optical fiber, tape, etc. ) passing along the length.

In FIG. 4 shows the waveguide 88 passing through the inner longitudinal channel 90 of the drill string 16, but in other examples, the waveguide may extend in the side wall of the drill string, outside the drill string, etc. The waveguide 88 may be in the form of a loop starting from the top of the flexible tubing, extending to the bottom, deploying and returning to the surface to improve the performance of temperature measurement.

Several optical waveguides 88 can be created along with other types of lines (e.g., power lines and / or hydraulic lines, etc.). Various lines can be included in the cable with additional components, such as armor, insulation, sheath, electrical lines, hydraulic lines and / or shielding, etc., or they can be separately installed in the drill string 16.

Optical waveguide 88 can be installed in a pipe or control line in drill string 16. Preferably, both single-mode and multi-mode optical waveguides 88 are equipped, but this does not have to be in accordance with the principles of the present invention.

The drill string 16 is preferably continuous (for example, not from links or sections) from at least wellhead equipment 24 to a location near the bottom of the drill string (for example, including, without limitation, sensors 60, a non-return valve 21, a drill bit 14, hydraulic downhole motor 92 (see Fig. 1), which rotates the drill bit under the action of a fluid stream 18 passing through the drill string, etc.). The waveguide 88 can be installed in the drill string 16 prior to the descent of the drill string into the wellbore 12 or after descent.

On the left in FIG. Figure 4 shows the situation of fluid loss 18 into formation 64. Here, fluid 18 flows from wellbore 12 into formation 64.

This situation may occur, for example, when the pressure in the wellbore 12 is greater than the hydraulic fracturing pressure 64. Such a situation should generally be avoided, but can be used to advantage (for example, for the convenience of determining hydraulic fracturing pressure, etc.), as described detail below.

To the right in FIG. 4 shows another situation in which formation fluid 94 flows into the wellbore 12 from the formation 64. This situation may occur, for example, when the pressure in the wellbore 12 is less than the pore pressure of the formation 64.

In general, this situation is required in downhole drilling (e.g., with controlled inflow of formation fluid 94 into wellbore 12 during drilling), but is undesirable in other types of drilling (e.g., controlled pressure drilling, conventional repression drilling, etc.). d.). In the methodology described in more detail below, the influx of formation fluid 94 into the wellbore 12 can be used to conveniently determine the pore pressure of the formation 64.

It should be noted that the fluid 18 should not flow into the reservoir 64 (as shown on the left in Fig. 4) simultaneously with the passage of the fluid 94 into the wellbore 12 (as shown on the right in Fig. 4). Thus, the situations shown left and right in FIG. 4 should not occur simultaneously, but instead are used to show individual situations that may arise during drilling.

In FIG. 5 shows a graph 96 of temperature versus depth for a section of a wellbore 12 of FIG. 4 and for the fluid loss situation 18 shown on the left in FIG. 4. It should be noted that a decrease in temperature 98 is detected at a position where fluid 18 enters formation 64.

The decrease in temperature 98 occurs due to local cooling by the fluid 18 of the formation 64 at the position where the fluid enters the formation. Such an anomaly of temperature decrease 98 can be used to determine the place and time of occurrence of fluid loss 18 and can be used to determine when hydraulic fracturing pressure 64 is reached.

In FIG. 6 is a graph 100 of temperature versus depth for a section of a wellbore 12 of FIG. 4, and for the fluid flow situation 94 shown on the right in FIG. 4. It should be noted that an increase in temperature 102 is detected at the position where the fluid 94 enters the wellbore 12.

The increase in temperature 102 occurs due to local heating by the fluid 94 of the wellbore 12 at the position where the fluid enters the wellbore. Such an anomaly in the increase in temperature 102 can be used to determine the place and time of occurrence of fluid influx 94, and can be used to determine when the pressure in the wellbore becomes less than the pore pressure of the formation 64.

Preferably, the temperature is measured by an optical waveguide 88 using a well-known distributed temperature measurement (DTS) technique. Distributed temperature measurement is a technology that can be used to measure the temperature distribution along the optical waveguide 88.

A pulsed laser source can be used to transmit a light pulse through an optical waveguide 88, and the properties of the returning reflected light can be recorded. Returning light (“reflected light”) contains the absorption and scattering of light energy.

Reflected light includes various spectral components, for example, Rayleigh, Brillouin and Raman scattering bands. Raman combined scattering band can be used to obtain temperature information on the fiber.

The reflection in the Raman Raman scattering band has two components, Stokes and anti-Stokes, the first is weakly dependent on temperature and the second is highly dependent on temperature. The relative intensity between the Stokes and anti-Stokes components is a function of the temperature at which back radiation occurs.

Since the speed of light in glass is known, it is possible to determine, when tracking the arrival time of reflected and backscattered light, the exact location of the occurrence of backscattered light. A track or profile of a distributed temperature measurement (such as graphs 96, 100 of FIGS. 5 and 6) is a group of temperature measurements or sample points spaced at equal intervals along the length of waveguide 88.

The Brillouin scattering backwash wavelength also depends on temperature, and this can be used for distributed temperature measurement. At the same time, the reverse radiation with Brillouin scattering also depends on the localized voltage in the waveguide 88, and therefore, for temperature measurements, the voltage component can be eliminated (for example, ensuring the absence of voltage in the waveguide), not taken into account, etc.

In the example of FIG. 4, an optical waveguide 88 is used for monitoring with distributed temperature measurement. At the same time, other methods of distributed measurements in the optical range can be used, if required. For example, distributed acoustic measurement (DAS), distributed voltage measurement (DSS) or distributed vibration measurement (DVS) can be used.

As discussed above, Raman Raman scattering measurement is used to monitor a distributed temperature measurement, but Brillouin optical scattering measurement of back radiation can also be used if required. The Brillouin or Rayleigh scattering measurement can be used to monitor a distributed acoustic measurement, a distributed voltage measurement, or a distributed vibration measurement, preferably with a measurement of the Brillouin scattering gain or coherent Rayleigh scattering in the return radiation. Interferometric optical measurement can also (or alternatively) be used.

In one example, distributed acoustic measurement can be used to measure the acoustic signal when fluid 94 flows into wellbore 12 from formation 64 (e.g., fluid influx), or reduced acoustic amplitude due to fluid 18 flowing out of the wellbore into formation (e.g., fluid loss). Other drilling characteristics (such as vibration of drill string 16, sticking and slipping, swirling motion, stress, etc.) can also, or alternatively, be measured using an optical waveguide 88.

The distributed acoustic measurement can be used to determine the acoustic signature of the gas entering the wellbore 12 from the formation 64 and / or the gas flowing through the annular space 20. For example, the waveguide 88 should indicate reduced damping of acoustic damped vibrations in sections of the drill string 16 exposed to gas in the wellbore 12, so that optical equipment connected to the waveguide can be used to determine the distributed acoustic resonance in the drill string not for this purpose.

Using this, it is possible to equip an early gas detection system where not only an inflow event can be detected, but also the location of the inflow in the wellbore 12, and the location and speed of the gas in the annular space 20. Such information can enable the rig personnel to make appropriate adjustments at the right times. time for the circulation of gas with the release from the wellbore 12 and to prevent additional inflows.

Distributed acoustic measurement can be used to determine the acoustic waves produced by another drill string (not shown) in another close borehole (not shown). When a different borehole is drilled with another drill string, the waveguide 88 detects acoustic waves produced by the other drill string, so that the location of the other borehole relative to the borehole 12 can be easily determined to direct the borehole to meet or to breed one with the other.

Distributed acoustic measurement can be used to determine other events in the wellbore 12 or beyond that can transmit an acoustic signal. For example, erosion occurring in wellbore 12 can be detected by waveguide 88. As another example, a seismic source can be activated on the surface, in another wellbore, etc., and seismic vibrations can be detected by waveguide 88.

In addition to distributed measurements, a point measurement of properties can be performed using one or more sensors 104. For example, sensors 104 may include a pressure sensor, a chemical ion or pH sensor, an ionizing radiation sensor, a magnetic field sensor, etc. Sensors 104 may be optical or other types of sensors, and may or may not be connected to waveguide 88 or part thereof.

In other examples, the sensors 104 are not necessarily optically coupled to the waveguide 88. Instead, the sensors 104 can be acoustically coupled to the waveguide 88. In this example, the sensors 104 can transmit acoustic signals in which their measurements are modulated (for example, using frequency, phase or amplitude manipulation, etc.), acoustic signals can be received by waveguide 88 and transmitted optically (as variations of the reflected signal) to a remote site (such as the earth's surface, a drilling rig, equipment Maintenance wellhead on the sea floor, etc.).

Additionally, you can create one or more lines 106, if required. In one example, line 106 comprises an electrical conductor, which serves as an antenna generating a magnetic field in formation 64. Changes in magnetic field indicate changes in resistivity in formation 64.

The well-known Faraday effect in waveguide 88 can be detected as an indication of a change in the magnetic field in the formation 64. In this example, the drill string 16 can be made of composite or other non-magnetic material that does not interfere with the propagation of the magnetic field in the formation 64, and to determine the change in the magnetic field strength layer.

In one example, logging can be performed by waveguide 88 during drilling. The waveguide 88 may, for example, detect gamma radiation from the reservoir 64. In this method, the operator can determine the moment of penetration of a particular underground layer, the layers adjacent to the drill string 16 can be correlated with the predicted underground layers, etc. In this example, the drill string 16 should preferably be made of composite or other non-metallic material.

Ionizing radiation can be detected along waveguide 88, creating a phosphorescent or fluorescent shell on the waveguide. Different layers can have different spectral absorption signatures, which allows identification and confirmation of layers based on signatures.

Only some examples of distributed and spot measurement techniques using waveguide 88 are described above, but it is clear that any measurement technique, and any number or combination of measurement techniques, can be used according to the principles of the present invention.

In FIG. 7, a method 108 that can be used with the downhole system 10 in the configuration of FIG. 4 is shown in the form of a flowchart. Of course, method 108 can be practiced in other downhole systems in accordance with the principles of the present invention.

In method 108, the influx of formation fluid 94 is detected by indicating the pore pressure of the formation 64. When the pressure in the wellbore 12 at some location is less than the pore pressure of the formation 64 at that location, the differential pressure causes the formation fluid 94 to flow into the wellbore and into the wellbore.

Thus, the start point of the inflow is the point at which the pressure in the wellbore 12 becomes less than the pore pressure of the formation 64. The pressure in the wellbore 12 can be easily measured (for example, using sensors 60, 104, etc.), and the pressure in The annular space 20 near the surface is conveniently measured (for example, using sensors 38, 40, etc.) when such an inflow occurs.

It should be noted that the pressure in the wellbore 12 at the inflow position may include frictional pressure losses due to fluid flow 18 (also known as equivalent circulation density), so these pressure losses (if any) are preferably taken into account when determining the actual pressure in the wellbore wells in the inflow position. At the same time, it is not necessary to circulate the fluid 18 through the drill string 16 and the annular space 20 when performing method 108. Instead, pump 70 (see FIG. 1) and / or mud pump 68 (see FIG. 3) can use to supply flow through the nozzle 34 in the method 108, when there is no circulation of fluid 18 through the drill string 16 and the annular space 20.

At step 110 of method 108, fitting 34 is adjusted to gradually reduce pressure in wellbore 12. When reducing the resistance to flow through the nozzle 34 (for example, by gradually opening the nozzle), the pressure upstream of the nozzle is reduced, while the pressure applied to the annular space 20 near the surface decreases.

At 112, an inflow is detected. For example, using distributed acoustic measurement or distributed temperature measurement by waveguide 88, as described above, an acoustic or thermal flow indication can be easily detected (for example, as shown in FIG. 6).

The pressure in the wellbore 12 in the inflow position can be measured (for example, using sensors 60, 104, etc.), and / or the pressure in the annular space 20 near the surface can be measured (for example, using sensors 38, 40, etc. d.) at the time of the influx. Pressure measurement data should indicate the pore pressure of formation 64 in the inflow position.

At 114, the fitting 34 is adjusted appropriately for a particular drilling operation. For example, in controlled-pressure drilling, the nozzle 34 can be adjusted to maintain the pressure in the wellbore 12 slightly higher than the pore pressure of the formation 64 (which can subsequently be confirmed by the absence of inflow detection by the waveguide 88 after adjusting the nozzle). In downhole drilling, the nozzle 34 can be adjusted so that an adjustable inflow volume is created during drilling (which can subsequently be confirmed by the waveguide 88 after adjusting the nozzle).

In addition to FIG. 8 shows another method 130 that can be used in the downhole system 10 in the configuration of FIG. 4 in the form of a flowchart. Of course, the method 130 can be practically implemented in other downhole systems, in accordance with the principles of the present invention.

In method 130, loss of fluid 18 into formation 64 is detected as an indication of the fracture pressure. When the pressure in the wellbore 12 at some location is greater than the fracture pressure of the formation 64 at that location, cracks can open in the formation and fluid 18 can easily go into the formation.

Thus, the point at which the loss of fluid 18 begins is the point at which the pressure in the wellbore 12 becomes greater than the fracturing pressure of the formation 64. The pressure in the wellbore 12 can be easily measured (for example, using sensors 60, 104, etc. .), and the pressure in the annular space 20 near the surface is conveniently measured (for example, using sensors 38, 40, etc.) with a loss of fluid 18.

It should be noted that the pressure in the wellbore 12 in the fluid loss position may include friction pressure loss due to fluid supply 18 (also known as equivalent circulation density), so that these pressure losses (if any) are preferably taken into account when determining the actual pressure in the wellbore in a fluid loss position. At the same time, it is not necessary to circulate the fluid 18 through the drill string 16 and the annular space 20 when performing method 130. Instead, pump 70 (see FIG. 1) and / or mud pump 68 (see FIG. 3) can used to supply flow through the nozzle 34 in the method 130, when there is no circulation of fluid 18 through the drill string 16 and the annular space 20.

At step 132 of method 130, fitting 34 is adjusted to gradually increase pressure in wellbore 12. With increasing resistance to flow through the nozzle 34 (for example, by gradually closing the nozzle), the pressure upstream of the nozzle increases, while the pressure applied to the annular space 20 near the surface increases.

At step 134, fluid loss 18 is detected. For example, using distributed acoustic measurement or distributed temperature measurement by waveguide 88, as described above, an acoustic or thermal indication of fluid loss 18 can be easily detected (for example, as shown in FIG. 5).

The pressure in the wellbore 12 in the fluid loss position can be measured (for example, using sensors 60, 104, etc.) and / or the pressure in the annular space 20 near the surface can be measured (for example, using sensors 38, 40, etc. d.) in case of loss. Pressure measurement data should indicate fracture pressure of formation 64 at the fluid loss position.

At 136, the fitting 34 is adjusted appropriately for a particular drilling operation. For example, in drilling under controlled pressure, the nozzle 34 can be adjusted to maintain the pressure in the wellbore 12 slightly higher than the pore pressure of the formation 64 (which can subsequently be confirmed by the absence of inflow detection by the waveguide 88 after adjusting the nozzle) and less than the fracturing pressure. In downhole drilling, the nozzle 34 can be adjusted so that an adjustable inflow volume is created during drilling (which can subsequently be confirmed by the waveguide 88 after adjusting the nozzle).

It should be understood that the invention described above creates several advantages compared with the known technical solutions for regulating the pressure in the wellbore and measuring parameters in drilling operations. In the example of FIG. 4, a flexible tubing or other drill string 16 in the form of a continuous tubing includes an optical waveguide 88 that provides distributed and / or point measurement of various parameters. The use of the drill string 16 in the form of a continuous tubing with an optical waveguide 88 here provides a convenient descent of the drill string and waveguide into the wellbore 12 and their rise from the wellbore without requiring the waveguide to be attached to the outer surface, or to detach the waveguide from the outer surface of the drill string connecting drill string sections to the string or disconnecting them from the string.

The above invention describes a method for drilling a wellbore 12. The method may include the steps of drilling a wellbore 12 by means of a drill string 16 of the tubing and measuring at least one parameter by means of an optical waveguide 88 in the drill string 16.

The drill string 16 may be continuous at least from equipment on the surface to the layout of the bottom of the drill string 16.

The measurement of at least one parameter may comprise measuring a parameter distributed along the drill string 16.

Distributed Acoustic Measurement (DAS), Distributed Temperature Measurement (DTS), Distributed Vibration Measurement (DVS) and / or Distributed Voltage Measurement (DSS) may be included in the measurement of at least one parameter.

The measured parameter can be selected from the group including pressure, temperature, chemical ion, ionizing radiation, pH, magnetic field and gamma radiation. Of course, any other parameter (s), and any number or combination of parameters, can be measured according to the principles of the present invention.

The method 108 may include stages in which the nozzle 34 is regulated, thereby creating an influx of fluid 94 into the wellbore 12, the measurement of at least one parameter may include the stage of determining the inflow. The method 108 may also include the step of measuring the pressure in the wellbore 12 when determining the inflow by correlating the pressure in the wellbore 12 with the pore pressure in the formation 64 passed by the wellbore 12. Method 108 may also include the step of adjusting fitting 34 in response to determining inflow.

The method 130 may include adjusting the fitting 34, thereby causing loss of fluid 18 from the wellbore 12, the measurement of at least one parameter may include determining the loss of fluid 18. Method 130 may also include the stage at which the pressure in the wellbore 12 is measured when determining the loss of fluid 18 when the pressure in the wellbore 12 is correlated with the fracturing pressure in the formation 64 passed by the wellbore 12. The method 130 may also include adjusting the fitting 34 in response to determining a loss of fluid 18.

The optical waveguide 88 may be located in the inner channel 90 of the flow of the drill string 16.

The borehole system 10 is also disclosed in the above description. The borehole system 10 may comprise a continuous drill string 16 of the tubing, and an optical waveguide 88 in the drill string 16. The optical waveguide 88 may measure at least one parameter along the drill string 16.

It should be understood that the various embodiments of the present invention described herein can be used in various orientations, such as oblique, inverted, horizontal, vertical, etc. and in various configurations without departing from the principles of the present invention. The embodiments are described only as examples of the beneficial application of the principles of the invention, which are not limited to any specific details of these embodiments.

After a careful review of the above description of embodiments of the invention, one skilled in the art will appreciate that many modifications, additions, substitutions, exceptions, and other changes can be made in specific embodiments, and such changes are consistent with the principles of the present invention. Accordingly, the above detailed description should be understood solely as an illustration and example, and the essence and scope of the present invention are limited only by the attached claims and their equivalents.

Claims (26)

1. A method of drilling a wellbore, comprising the steps of:
drilling a wellbore by means of a continuous drill string of tubing;
measuring at least one parameter with an optical waveguide in the drill string, the measurement including the step of determining optical backscattering along the optical waveguide; and
adjust the nozzle, thereby causing fluid to flow into the wellbore or fluid loss from the wellbore, the measurement of at least one parameter further includes the step of determining fluid flow or fluid loss. 2. The method of claim 1, wherein the drill string is continuous from at least a surface position to a bottom assembly of the drill string. 3. The method according to claim 1, in which the measurement of at least one parameter includes the step of measuring the parameter as distributed along the drill string. 4. The method according to p. 1, in which the measurement of at least one parameter includes the step of performing a distributed acoustic measurement. 5. The method according to p. 1, in which the measurement of at least one parameter includes the step of performing a distributed temperature measurement. 6. The method according to p. 1, in which the measurement of at least one parameter includes the step of performing a distributed vibration measurement. 7. The method according to p. 1, in which the measurement of at least one parameter includes a step in which a distributed voltage measurement. 8. The method according to p. 1, in which at least one parameter is selected from the group including: pressure, temperature, chemical ion, ionizing radiation, pH, magnetic field and gamma radiation. 9. The method according to claim 1, further comprising the step of measuring the pressure in the wellbore when determining the inflow, wherein the pressure in the wellbore is correlated with the pore pressure in the formation passed by the wellbore. 10. The method of claim 1, further comprising the step of adjusting the fitting in response to determining the inflow. 11. The method according to p. 1, further comprising the step of measuring the pressure in the wellbore when determining fluid loss, the pressure in the wellbore being correlated with the fracture pressure passed by the wellbore. 12. The method of claim 1, further comprising adjusting the fitting in response to determining fluid loss. 13. The method according to p. 1, in which the optical waveguide is located in the internal channel of the flow of the drill string. 14. A downhole system comprising:
a continuous drill string of the tubing and an optical waveguide in the drill string, the optical waveguide measuring at least one parameter along the drill string by determining optical backscatter along the optical waveguide, and
a fitting whose regulation causes fluid inflow into the wellbore or fluid loss from the wellbore, wherein at least one parameter is an indication of fluid inflow or loss. 15. The system of claim 14, wherein the drill string is continuous from at least a surface position to a bottom assembly of the drill string. 16. The system of claim 14, wherein the optical waveguide measures at least one parameter as being distributed along the drill string. 17. The system of claim 14, wherein the at least one parameter is distributed acoustic waves. 18. The system of claim 14, wherein the at least one parameter is a distributed temperature. 19. The system of claim 14, wherein the at least one parameter is distributed vibration. 20. The system of claim 14, wherein the at least one parameter is a distributed voltage. 21. The system according to p. 14, in which at least one parameter is selected from the group including: pressure, temperature, chemical ion, ionizing radiation, pH, magnetic field and gamma radiation. 22. The system of claim 14, wherein the pressure in the wellbore when indicating the inflow is correlated with pore pressure in the formation passed by the wellbore. 23. The system of claim 14, wherein the fitting is adjusted in response to an indication of flow. 24. The system of claim 14, wherein the pressure in the wellbore when indicating fluid loss is correlated with the fracture pressure in the formation passed by the wellbore. 25. The system of claim 14, wherein the fitting is adjusted in response to an indication of fluid loss. 26. The system of claim 14, wherein the optical waveguide is located in the inner channel of the drill string.

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