NO349218B1 - Subsea wellbore pipe cutting tool with cut verification and method - Google Patents

Description

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S<UBSEA WELLBORE PIPE CUTTING TOOL WITH CUT VERIFICATION>

Technical Field

[0001] The present invention relates to a well pipe cutting tool with a cutting verification arrangement.

Background Art

[0002] In some situations, during the lifetime of a subterranean hydrocarbon well, the operator may need to cut off a pipe inside the well. A typical situation is when a well casing shall be pulled out of the well.

[0003] Cutting tools for performing such downhole cutting operations are well known. The tool typically comprises a set of radially expandable arms provided with cutting means. The tools disclosed in US20190003260A1 and NO346248B1 are examples of such cutting tools.

[0004] Another example is shown in publication US2022412179A1, which discloses a cutting tool and a control device that operates the cutting process based on measured feedback.

[0005] After the cutting operation, it sometimes happens that the well pipe has not been completely cut through without the operator being aware. For instance, if the operator attempts to pull a casing without success, the reason can be that the casing is stuck in the well (e.g. due to settled barite). It may, however, also be due to an incomplete cutting of the casing. Knowledge of the reason is crucial to the operator for planning and conducting the succeeding operations.

[0006] Techniques exist for verifying that the well pipe has been cut through.

Typically, the torque of the rotating drill pipe is monitored, wherein a drop of torque indicates that the pipe is cut. Furthermore, monitoring the pressure in the drill pipe will also give an indication of a cut pipe when pressure drops.

[0007] Publication GB2373266A discloses a tubular cutting tool for cutting well tubulars. It has a motor-driven cutting blade configured to be moved radially outwards for cutting the tubular from the inside. During the cutting process, the electric current consumption and rpm of the rotary cutting head are monitored remotely, via telemetry, by the operator. Once the cutting blade has advanced enough, and the

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tubular is fully cut, the operator observes a drop in power consumption and instructs the tubular cutting tool to stop.

[0008] Despite the existing monitoring techniques, operators still experience that the well pipe is not fully cut after a cutting operation. An object of the present invention may thus be to provide a solution for verifying a successful cut of the well pipe after performing a cutting operation.

Summary of invention

[0009] According to a first aspect of the present invention, there is provided a subsea wellbore pipe cutting tool, comprising one or more radially movable cutting means and a downhole cut verification arrangement. The downhole cut verification arrangement comprises a downhole cut verification sensor. The downhole cut verification arrangement may further comprise a control unit to which the downhole cut verification sensor is connected. The downhole cut verification sensor comprises an upper bore contact device and a lower bore contact device extending radially outwards beyond a main body of the cutting tool above and below the radially movable cutting means, respectively. A control unit, for instance a control unit being part of the cutting tool or a topside control unit, is configured to apply an electric signal to the upper and lower bore contact devices and to record electric signal characteristics during a cutting process.

[0010] Typically, the applied electric signal can be electric direct current (DC) flowing between the upper and lower bore contact devices, through the well pipe that shall be cut, as both contact devices contact the well pipe. When the electric current stops flowing, or at least drops significantly, the cut is probably complete. Other types of electric signals may also be applied, for instance alternating current, wherein the measured characteristic parameter can comprise capacitance.

[0011] It shall be appreciated that the downhole cut verification arrangement or the downhole cut verification sensor may be a part of the cutting tool or may, in some embodiments, be part of the tool string of which the cutting tool constitutes a part.

[0012] By stating that the cut verification arrangement is a downhole cut verification arrangement is meant that the arrangement is part of the tool string configured to be

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arranged downhole, such that the downhole cut verification sensor can be arranged proximate to the location of the cutting process. By using a sensor arranged downhole, i.e. proximate to the cutting process, the determination of the completeness of the cutting process is facilitated.

[0013] The control unit can typically comprise a logic unit configured to receive measured cutting parameters and optionally store the received parameters in a memory unit.

[0014] In scenarios where recorded cutting parameters are stored in the memory unit of the control unit, the operator can read the stored cutting parameters once the cutting tool has been retrieved to the surface. The operator is then enabled to evaluate whether the performed cutting process was successful. In further scenarios, the recorded parameters may be communicated to the surface during the cutting operation, such as when the cutting tool is run on a wired drill pipe.

[0015] In some embodiments, the downhole cut verification sensor comprises an acoustic sensor. With the acoustic sensor, the sound of the cutting operation can be recorded. Since the sound of the cutting operation will change during the cutting operation (for instance, the sound amplitude will be lower when the well pipe is fully cut through), this will enable the operator to determine the successfulness of the cutting process.

[0016] In some embodiments, the downhole cut verification sensor may in addition comprise an ultrasound imaging arrangement. In such embodiments, an ultrasound image of the cut portion of the well pipe can be obtained, enabling the operator to visually inspect the cut, and thus determine the successfulness of the cutting process.

[0017] The downhole cut verification sensor may also comprise an internal pressure sensor arranged in fluid communication with a cutting arm actuation chamber of the cutting tool. Since the pressure in the cutting arm actuation chamber will drop once the well pipe is fully cut through, monitoring the pressure in the cutting arm actuation chamber enables the operator to determine if the cut is successful. By recording the pressure on site, i.e. at the downhole location, the sensed pressure value will be more accurate compared to a pressure recording topside.

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[0018] The downhole cut verification sensor can in addition comprise an external pressure sensor arranged in fluid communication with the exterior of the cutting tool. This may provide the operator information of the pressure changes occurring during the cutting process, typically when the well pipe is cut through, resulting in a pressure equalization between the bore of the cut well pipe and the annulus outside of it.

[0019]

[0020] The subsea wellbore pipe cutting tool may further comprise an electric or optic communication interface connected to a communication line extending to the topside. This enables the operator to obtain real-time recordings from the one or more downhole cut verification sensors.

[0021] In some embodiments, the downhole cut verification arrangement can comprise or be connected to a machine learning model configured to obtain data from the downhole cut verification sensor to determine whether the wellbore pipe cutting operation was successful.

[0022] According to a second aspect of the present invention, there is provided a method of verifying completeness of a wellbore pipe cutting operation. The method comprises the following steps:

a) lowering a tool string comprising a cutting tool into a subsea wellbore pipe; b) actuating a radially movable cutting means and cutting the wellbore pipe;

c) during step b), recording cutting parameters associated with the cutting process, obtained from a downhole cut verification sensor; and

d) determining, based on the recorded cutting parameters in step c), a probability of a successful cut. Step c) comprises recording cutting parameters with the following downhole cut verification sensors:

- an upper bore contact device and a lower bore contact device extending radially outwards beyond a main body of the cutting tool, above and below the radially movable cutting means, respectively. A control unit is configured to apply an electric signal to the upper and lower bore contact devices and to record electric signal characteristics during a cutting process in step b).

[0023] Step d) can for instance be performed with a computer or by a person, or both.

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[0024] In some embodiments, step c) can also comprise recording cutting parameters with one or more of the following downhole cut verification sensors:

- an external pressure sensor in fluid communication with the exterior of the cutting tool;

- an internal pressure sensor in fluid communication with a cutting arm actuation chamber of the cutting tool;

- an acoustic sensor;

- an ultrasonic imaging arrangement.

[0025] Moreover, in some embodiments of the second aspect of the invention, step d) can comprise using a trained machine learning model to determine whether the wellbore pipe cutting operation was successful, wherein the trained machine learning model is configured to estimate a verification value associated with the wellbore pipe cutting operation based on recorded cutting parameters.

Detailed description of the invention

[0026] While various features of the invention have been discussed in general terms above, some non-limiting examples of embodiment are presented in the following with reference to the drawings, in which

Fig. 1a to Fig.1c are schematic views of a pipe cutting tool cutting a wellbore casing;

Fig. 2 is a schematic cross-section view of a cutting tool, illustrating actuation of radially movable cutting arms;

Fig. 3 is a schematic illustration of the components of a cut verification arrangement;

Fig. 4 depicts various curves that, when interpreted, indicate the completeness of the cutting process;

Fig. 5 depicts a curve resulting from audio recording of the cutting process;

Fig. 6 is a schematic cross-section view through a portion of the cutting tool, illustrating a cutting tool with an ultrasound imaging device; and

Fig. 7 illustrates a schematic example of an ultrasound image of an unsuccessful cut.

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[0027] Fig. 1a depicts a well pipe cutting tool 10 that is a part of a tool string 1 that has been lowered into a subterranean well. The cutting tool 10 is arranged in the bore of a well casing 11. The cutting tool 10 can typically be run on a drill pipe (not shown). This enables the operator to rotate the cutting tool 10 inside the casing 11. Other embodiments are however also possible. For instance, the cutting tool 10 can be run on a wire, in which case it would need a motor for the cutting operation.

[0028] The cutting tool 10 comprises a plurality of radially movable cutting means. In this embodiment, the cutting means are in form of cutting arms 13. Fig.1b depicts the cutting tool 10 when in a cutting mode, as the cutting arms 13 extend out from the main body of the cutting tool 10. When in the cutting mode, the cutting tool 10 is rotated such that the cutting arms 13 cut through the casing 11 from the inside.

[0029] Fig. 1c depicts the cutting tool 10 after the cutting operation. The cutting arms 13 have been radially retracted into the tool, and the casing 11 has been fully cut. If a tensile stress was present in the casing 11 before cutting, the cut parts may retract such that a significant distance appears between them at the cut location.

[0030] Fig. 2 depicts a schematic cross section view through a portion of the cutting tool 10. It will be understood that this is image is for the purpose of explaining the present invention and is simplified compared to a real cutting tool.

[0031] The cutting tool 10 has a main body 15 to which cutting arms 13 are attached. On the left-hand side of Fig.2, a cutting arm 13 is shown in a retracted position, while a cutting arm 13 is depicted in a cutting position on the right-hand side. The cutting tool 10 can typically have three cutting arms 13. Moreover, as the skilled reader will appreciate, the cutting arms 13 are provided with a hardened cutting edge suitable for cutting through well pipes, such as the depicted casing 11.

[0032] To move the cutting arms 13 from the retracted to the cutting position, the cutting tool 10 comprises an actuation member, which in the present embodiment is in form of an actuation sleeve 17. The actuation sleeve 17 comprises a toothed section 19 that interfaces with a toothed segment 21 of the respective cutting arms 13. Moreover, the cutting arms 13 are supported on the cutting tool 10 by means of a respective pivot pin 23, about which they can rotate.

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[0033] To move the actuation sleeve 17, a hydraulic pressure is applied to a cutting arm actuation chamber 25. The hydraulic pressure acts on a sleeve piston 27 of the actuation sleeve 17.

[0034] When the actuation sleeve 17 moves to move the cutting arms 13 towards the cutting position, a spring 29 is compressed between the main body 15 and the actuation sleeve 17. Hence, when the hydraulic pressure of the cutting arm actuation chamber 25 is reduced, the spring 29 will force the actuation sleeve 17 and thus the cutting arms 13 back to the retracted position (left-hand side).

[0035] As the skilled person will realize, the cutting arms 13 can be actuated in other ways. For instance, an electric motor (not shown) may move the cutting arms 13. Moreover, instead of the cogged interface between the actuation sleeve 17 and the cutting arms 13, the cutting arms could for instance be actuated with a cutting arm sliding face sliding against an opposite actuation face of the actuation sleeve 17.

[0036] The cutting tool 10 further comprises a downhole cut verification arrangement 30. The downhole cut verification arrangement 30 is schematically illustrated in Fig.3 and is a part of the cutting tool 10. It is noted, however, that in some embodiments, the downhole cut verification arrangement 30 can be part of a tool string (not shown), of which the cutting tool 10 forms a part.

[0037] The downhole cut verification arrangement 30 comprises a control unit 31. The control unit 31 comprises a battery 33 and a memory unit 35.

[0038] In the shown embodiment, the downhole cut verification arrangement 30 further comprises an external pressure sensor 37. The external pressure sensor 37 is in fluid communication with the outside of the cutting tool 10. In Fig.2, the external pressure sensor 37 is depicted at an outer portion of the main body 15.

[0039] As shown in Fig.3, the external pressure sensor 37 connects to the control unit 31. Thus, the control unit 31 can monitor and store measured external pressure values.

[0040] The downhole cut verification arrangement 30 may alternatively or in addition comprise an internal pressure sensor 39. As depicted in Fig.2, the internal pressure sensor 39 is arranged in fluid communication with the cutting arm actuation chamber

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25. Hence, the control unit 31 can monitor and store measured pressure values of the cutting arm actuation chamber 25.

[0041] The one or more recorded pressure values can be communicated to the operator once the cutting tool 10 has been retrieved to surface. Alternatively, a communication line may be arranged between the cutting tool 10 and topside, such that the operator is enabled to monitor the pressure from surface during a cutting operation.

[0042] Fig. 4 schematically depicts, with pressure-time graphs, typical pressure value recordings of both the external pressure sensor 37 and the internal pressure sensor 39. The pressure measured with the external pressure sensor 37 is shown with continuous line P1, while the measured pressure in the cutting arm actuation chamber 25 (internal pressure sensor 39) is shown with the dashed line P2.

[0043] In this example, before the cutting tool 10 penetrates the wall of the well pipe or casing 11, the pressure outside the casing 11 (in the annulus) is lower than the pressure in its bore. Hence, once the cutting tool 10 cuts an opening in the casing wall, the pressure measured by the external pressure sensor 37 drops.

[0044] The pressure of the cutting arm actuation chamber 25, as measured by the internal pressure sensor 39, increases when the cutting arms 13 are forced against the wall of the casing 11. It remains at an elevated pressure value until the cutting arms 13 are no longer forced against the casing 11 in the radial direction.

[0045] The operator can use these pressure-time graphs as a verification or at least an indication that a complete cut of the casing 11 has been obtained.

[0046] Reference is again made to Fig.2. The downhole cut verification arrangement 30 can, alternatively or in addition, comprise an upper bore contact device 41 and a lower bore contact device 43. The upper and lower bore contact devices 41, 43 are configured to maintain electric contact between the cutting tool 10 and the casing 11. In the shown schematic illustration, they are drawn as brushes and could for instance be made of a plurality of flexible steel bristles.

[0047] As illustrated in Fig.2, the upper and lower bore contact devices 41, 43 connect to the control unit 31. By applying an electric signal to the upper and lower bore contact devices 41, 43, and recording how the signal changes when cutting the

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casing 11, the operator is enabled to verify or at least receive an indication of a successful cut of the casing 11. The electric signal can in some embodiments be a direct current that flows between the upper and lower bore contact devices 41, 43, through the casing 11. When the casing is fully cut, the current will stop flowing.

[0048] In some instances, the casing may touch the tool string or another external tubular both above and below the cutting location. Current will then still pass freely between the upper and lower bore contact devices 41, 43. Hence, instead of a direct current, one may apply an alternating current and measure the capacitance and/or impedance. When the casing is fully cut through, a notable change will be detected.

[0049] The upper and lower bore contact devices 41, 43 are also shown in Fig.3, connected to the control unit 31.

[0050] In Fig.4, the dash-dot line R illustrates measured electric resistance in the same chart as the pressure values P1, P2 discussed above. When the pressure inside the cutting arm actuation chamber 25 drops, the electric resistance simultaneously increases, indicating a complete cut through the casing 11.

[0051] Reference is again made to Fig.2 and Fig.3. The downhole cut verification arrangement 30 can alternatively or in addition comprise an acoustic sensor 45 (e.g. a microphone). The acoustic sensor 45 is configured to record sound. When the cutting arms 13 cut the casing 11, the produced sound will be detected by the acoustic sensor 45 and recorded by the control unit 31.

[0052] The characteristics of the recorded sound will differ depending on the stage of the cutting. Once the cutting arms 13 have cut through the casing 11, the volume or amplitude of the produced sound will be lower, as the cutting arms 13 will slide against the edges of the cut slit. The frequency of the produced sound will also differ as the cutting stages change.

[0053] Fig. 5 depicts a schematic example of sound recorded during a cutting process. At the left-hand side, the cutting arms 13 have not yet contacted the casing 11. The middle portion represents the noise produced during cutting. The right-hand part represents the sound produced when the casing 11 is fully cut, while the cutting arms 13 are still in their radially outer position.

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[0054] The downhole cut verification arrangement 30 may alternatively or in addition comprise an ultrasound imaging device 47. Fig.6 schematically depicts a side portion of the cutting tool 10 at a cross section without the cutting arms 13. At this cross section, the ultrasound imaging device 47 is visible.

[0055] As the cutting tool 10 is rotated, the ultrasound imaging device 47 can be used to obtain an image of the cut in the casing 11. As illustrated in Fig.3, the ultrasound imaging device 47 connects to the control unit 31, such that recorded images can be stored in the memory unit 35.

[0056] A resulting ultrasound image is schematically depicted in Fig.7. In this example, the cut 49 is incomplete, thus providing valuable information to the operator that the performed cutting operation was unsuccessful.

[0057] In some embodiments, the recorded parameters, such as sound, pressure, electric signal characteristics and the ultrasonic image, can be input to a machine learning model trained to determine the probability of a complete cut.

Advantageously, although only one of the possible parameters would suffice to obtain a determination, two or even more parameters could be input to the machine learning model, thus enhancing the accuracy or correctness of its output.

[0058] The claimed method may thus comprise a step wherein values recorded from one or more of the said downhole cut verification sensors is fed to a machine learning model to provide an output representing a probability of a successful cut. The machine learning model is trained using measured values collected by control unit 31, such as data stored in memory unit 35 and/or other data, such as historical measured values or simulated measured values.

[0059] For example, the machine learning model is trained to output a probability of a successful cut based on an input of any of values recorded from one or more of the downhole cut verification sensors, pressure values, electronic resistance, acoustic data, ultrasound data, or a combination thereof. Alternatively, the machine learning model is trained to output other data suitable for determining the success of a cut, such as a prediction of ultrasound image schematically depicted in Fig.7, a prediction of whether a cut was completed successfully, or a simulation of the cutting process based on the inputs. E.g., the machine learning model is a deep learning

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model configured to identify whether the cut was completed successfully by predicting areas that were or were not cut through.

[0060] In one embodiment, the machine learning model is a classifier stored, accessed by, or otherwise in communication with control unit 31, such as a support vector machine, a k-nearest neighbor, a naïve bayes algorithm, or an artificial neural network e.g. a convolutional neural network, an autoencoder, or a generative adversarial network. The machine learning model classifies the input data obtained from control unit 31, such as the verification sensor data, pressure values P1, P2, or electronic resistance R of Fig.4, as a successful cut or unsuccessful cut. Optionally, the classification output is stored in memory unit 35 where it can be accessed, transmitted, or used to further train the machine learning model. The machine learning model is trained using historical measured values stored in memory unit 35 or an external storage unit not shown, such as using backpropagation and/or gradient descent methods. Optionally, the machine learning model is updated based on measured values stored in memory unit 35 and/or verification sensor data.

Claims (7)

349218 12 Claims

1. A subsea wellbore pipe cutting tool (10), comprising

- one or more radially movable cutting means (13); and

- a downhole cut verification arrangement (30),

5 wherein the downhole cut verification arrangement (30) comprises a downhole cut verification sensor (41, 43), wherein the downhole cut verification arrangement (30) further comprises a control unit (31) to which the downhole cut verification sensor (41, 43) is connected, characterized in that

the downhole cut verification sensor comprises an upper bore contact device 10 (41) and a lower bore contact device (43) extending radially outwards beyond a main body (15) of the cutting tool (10), above and below the radially movable cutting means (13), respectively, wherein the control unit (31) is configured to apply an electric signal to the upper and lower bore contact devices (41, 43) and to record electric signal characteristics during a cutting process.

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2. A subsea wellbore pipe cutting tool (10) according to claim 1, wherein the downhole cut verification sensor comprises an acoustic sensor (45).

3. A subsea wellbore pipe cutting tool (10) according to any one of the

20 preceding claims, wherein the downhole cut verification sensor comprises an ultrasound imaging arrangement (47).

4. A subsea wellbore pipe cutting tool (10) according to any one of the preceding claims, wherein the downhole cut verification sensor comprises an 25 internal pressure sensor (39) arranged in fluid communication with a cutting arm actuation chamber (25) of the cutting tool (10).

5. A subsea wellbore pipe cutting tool (10) according to any one of the preceding claims, wherein the downhole cut verification sensor comprises an 30 external pressure sensor (37) arranged in fluid communication with the exterior of the cutting tool (10).

6. A subsea wellbore pipe cutting tool (10) according to any one of claims 1 to

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5, further comprising an electric or optic communication interface connected to a communication line extending to the topside.

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7. A method of verifying completeness of a wellbore pipe cutting operation, comprising

a) lowering a tool string comprising a cutting tool (10) into a subsea wellbore pipe (11);

b) actuating a radially movable cutting means (13) and cutting the wellbore

10 pipe (11);

c) during step b), recording cutting parameters associated with the cutting process, obtained from a downhole cut verification sensor (37, 39, 41, 43, 45, 47);

d) determining, based on the recorded cutting parameters in step c), a

15 probability of a successful cut,

characterized in that step c) comprises recording cutting parameters with the following downhole cut verification sensors:

- an upper bore contact device (41) and a lower bore contact device (43) extending radially outwards beyond a main body (15) of the cutting tool (10),

20 above and below the radially movable cutting means (13), respectively, wherein a control unit (31) is configured to apply an electric signal to the upper and lower bore contact devices (41, 43) and to record electric signal characteristics during a cutting process in step b).

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