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Title:
A MOBILE OFFSHORE DRILLING UNIT AND METHOD OF CONTROLLING A PROCESS AUTOMATION SYSTEM
Document Type and Number:
WIPO Patent Application WO/2021/078993
Kind Code:
A1
Abstract:
The invention is related a floating mobile offshore drilling and a method of controlling a process automation system thereon. The floating mobile offshore drilling rig comprising a wave prediction system, a movement predictor unit, a process automation system configured to perform at least one operational sequence on board the mobile offshore drilling unit within a predetermined safe operating envelope. The process automation system is configured to enable at least one operational sequence when predicted movement of the mobile offshore drilling unit is within a predetermined safe operating envelope for the at least one operational sequence.

Inventors:
BORSHOLM THOMAS (NO)
LUND PER (NO)
Application Number:
PCT/EP2020/080006
Publication Date:
April 29, 2021
Filing Date:
October 26, 2020
Export Citation:
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Assignee:
ODFJELL DRILLING AS (NO)
International Classes:
B63B35/44; B63B79/15; B63B79/20; B63B79/30; B63B79/40; E21B7/12; E21B21/00; E21B21/08; E21B44/00; G01C13/00
Attorney, Agent or Firm:
ONSAGERS AS (NO)
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Claims:
CLAIMS

1. Floating mobile offshore drilling unit (1) comprising:

- a wave prediction system (5) comprising:

- at least one sensor (2) configured to detect and measure waves approaching the mobile offshore drilling unit (1), and

- a wave prediction unit (6) for receiving data from the at least one sensor (2), the wave prediction unit (6) being configured to, in response to the received data, predict timing and/or physical characteristics of the approaching waves when reaching the mobile offshore drilling unit (1); - a movement predictor unit (7) for receiving the predicted timing and/or physical characteristics of the waves from the wave prediction system, the movement predictor unit (7) being configured to, in response to the predicted timing and/or physical characteristics of the waves, predict movement of the mobile offshore drilling unit (1);

- at least one process automation system (8) configured to perform at least one operational sequence on board the mobile offshore drilling unit within a predetermined safe operating envelope; and wherein the at least one process automation system (8) is further configured to enable the at least one operational sequence when the predicted movement of the mobile offshore drilling unit is within the predetermined safe operating envelope for the at least one operational sequence. 2. The floating mobile offshore drilling unit of claim 1, wherein the at least one process automation system (8) initiates the at least one operational sequence automatically.

3. The floating mobile offshore drilling unit of any of the preceding claims, wherein the at least one process automation system (8) is configured to present a ready signal to an operator prior to initiating the at least one operational sequence.

4. The floating mobile offshore drilling unit of any of the preceding claims, wherein the at least one process automation system (8) is configured to move a drill string slowly up and down prior to the enabling of the at least one operational sequence.

5. The floating mobile offshore drilling unit of any of the preceding claims, further comprising a digital twin representing an object or system the rig is interfacing or working on, wherein the digital twin determines the safe operating envelope for the at least one operation sequence at any time, based on the predicted movement of the mobile offshore drilling unit input to the digital twin.

6. The floating mobile offshore drilling unit of claim 5, wherein the object or system that the rig is interfacing or working on is a drill string and a well. 7. The floating mobile offshore drilling unit of any of the preceding claims, wherein the at least one sensor (2) is a radar, an infrared sensor, a lidar, a camera, or a combination thereof.

8. The floating mobile offshore drilling unit of claim 8, wherein the sensor (2) is a radar for scanning over a sea horizon and wherein the radar detects and reads each approaching wave for giving information about the wave shape, location and speed.

9. Method of controlling a process automation system (8) on a floating mobile offshore drilling unit, the method comprising the steps of:

-receiving information of waves approaching the mobile offshore drilling unit from at least one sensor (2) on the mobile offshore drilling unit (1),

- predicting, in response to the received data, timing and/or physical characteristics of the approaching waves when reaching the mobile offshore drilling unit (1), - predicting, in response to the predicted timing and/or physical characteristics of the waves , movement of the mobile offshore drilling unit, and

- enabling at least one operational sequence on board the mobile offshore drilling unit (1) when the predicted movement of the mobile offshore drilling unit (1) is within a predetermined safe operating envelope for the at least one operational sequence.

10. The method of claim 9, wherein following the enabling of the at least one operational sequence, the method further comprising initiating the at least one operational sequence automatically.

11. The method of any of claims 9 or 10, wherein following the enabling of the at least one operational sequence, the method further comprising presenting a ready signal to an operator prior to initiating the at least one operational sequence. 12. The method of any of claims 9-11, wherein the method further comprises moving a drill string slowly up and down prior to the enabling of the at least one operational sequence.

13. The method of any of claims 9-12, wherein the method further comprises: inputting the predicted movement of the mobile offshore drilling unit to a digital twin representing an object or system the rig is interfacing or working on, and determining with the digital twin the safe operating envelope for the at least one operational sequence at any time based on the predicted movement of the mobile offshore drilling unit.

Description:
A MOBILE OFFSHORE DRILLING UNIT AND METHOD OF CONTROLLING A PROCESS AUTOMATION SYSTEM

The present invention relates to a floating mobile offshore drilling unit and a method of controlling a process automation system on a floating mobile offshore drilling unit.

Background

Drilling and well intervention operations for a floating Mobile Offshore Drilling Units (MODU) may be limited by rig heave and rig movements. Therefore, some MODU are provided with a hoisting system with heave compensation systems to compensate for the rig heave and the rig movements during operations that are sensitive to rig movements.

While the heave compensation systems can be efficient under most circumstances, there are some operations that require that the heave compensation is turned off. Such operations include, but are not limited to, connecting and disconnecting pipe stands to the drill string, an operation that require the drill string to be hung off in the rig’s drill floor. Other rig operations that are critical with regard to rig movements are landing of Blowout Preventer (BOP) and Lower Marine Riser Package (LMRP), running of completion, landing of liners and completions, heavy lifts from the rig using the rig crane, and launch and recovery of Remote Operated Vehicles (ROVs) or other subsea equipment.

Prior art for predicting rig movements rely on generic and coarse systems like weather forecasts and heave response models. Such systems can predict average and worst sea conditions but will not be able to provide an accurate prediction of the rig movement in the time domain. As prior art floating mobile offshore drilling units do not have a system to precisely predict rig heave and rig movements, an operator is required to apply conservative safe operating limits thus shutting down operations earlier than necessary, or risk damages to the equipment or the well.

Some of the most critical safe operating limits in a drilling operation are the pressure limits for wellbore stability; pore and fracture pressure. The drilling fluid needs to have rheological properties to keep the downhole pressure below the pressure that will fracture the well and above the pressure that will collapse the well. In addition to the downhole hydrostatic pressure from the drilling fluid, there are dynamic pressure components like from Equivalent Circulating Density (ECD), drill string movement and gel breaking when the is put into motion from being static. Publication US 10323474 B2, discloses a heave compensated managed pressure drilling system for controlling borehole pressure in a MPD system to compensate for heave effects on the drilling rig. The publication discloses that the data collected by sensors may be used to predict appropriate set points for well system equipment. By tracking the wave patterns, the control system may recognise patterns (e.g. every seventh wave slightly larger than the waves immediately before and after it). The set points are dynamically calculated and providing set points to multiple MPD components to enable control of borehole pressure such that pressure is maintained within a desired pore-pressure facture-gradient window even during changing pressure conditions.

The system in publication US 10323474 B2, uses wave data to establish a generalized motion pattern based on an imaginary generalized historical wave pattern. This system may have the challenges that it is unable to predict specific extreme wave approaching, nor a period of calm waves. It can only give a “most probably” wave pattern scenario based on measured and historical data, and it cannot take into account if the sea state is getting worse or better. Another weakness of this system is that it is based on the assumption that the waves always occur in patterns, which is not true.

The objective of the present invention is to provide a system and method than can give a more accurate prediction of wave and drilling unit movement to identify safe operation envelope for an operational sequence.

Summary of the invention

In one aspect of the present invention it is provided a floating mobile offshore drilling unit. The floating mobile offshore drilling unit comprising a wave prediction system, the wave prediction system comprising at least one sensor configured to detect and measure waves approaching the mobile offshore drilling unit, and a wave prediction unit for receiving data from the at least one sensor, the wave prediction unit configured to, in response to the received data, predict timing and physical characteristics of the approaching waves when reaching the mobile offshore drilling unit.

The physical characteristics of the wave may include wave characteristics such as wave height, wave length, wave shape, wave period and wave propagation (direction). A combination of several waves on top of each other, each with its own characteristics, may be represented in a wave spectrum. The term “timing” is referring to the travelling speed and the estimated time of arrival of each wave. The prediction may be based on how the detected waves from the wave prediction unit propagates over time.

The floating mobile offshore drilling unit further comprises a movement predictor unit receiving predicted timing and/or physical characteristics of the waves from the wave prediction system, the movement predictor unit being configured to, in response to the predicted timing and/or physical characteristics of the waves, predict movement of the mobile offshore drilling unit.

The movement predictor unit may predict movement of the mobile offshore drilling unit based on actual measured data from the one or more sensors. The movement predictor unit may continuously receive updated predicted timing and/or physical characteristics of the waves from the wave prediction system. This may allow the movement predictor unit to continuously update the predicted movement of the mobile offshore drilling unit.

The floating mobile offshore drilling unit further comprises at least one process automation system configured to perform at least one operational sequence on board the mobile offshore drilling unit within a predetermined safe operating envelope, wherein the process automation system is further configured to enable the at least one operational sequence when the predicted movement of the mobile offshore drilling unit is within the predetermined safe operating envelope for the at least one operational sequence. The at least one process automation system may be configured to initiate the at least one operational sequence automatically.

Alternatively, or additionally, in one embodiment the at least one process automation system may be configured to present a ready signal to an operator prior to initiating the at least one operational sequence.

The at least one process automation system may be configured to move the drill string slowly up and down prior to the enabling of the at least one operational sequence.

The floating mobile offshore drilling unit may further comprise a digital twin representing an object or system that the rig is interfacing or working on. Such a system may be the drill string and the well with its rock formation, cement, casing and fluids which all have varying mechanic, hydraulic and thermic characteristics. Another example object may be a supply vessel that moves in the waves and from its propulsion.

The digital twin determines the safe operating envelope for the at least one operation sequence at any time, based on the predicted movement of the mobile offshore drilling unit input to the digital twin. The at least one sensor may be a radar, an infrared sensor, a lidar, a camera or a combination thereof.

A radar system may comprise a transmitter producing electromagnetic waves in the radio or microwaves domain, a transmitting antenna, a receiving antenna (same antenna may be used for transmitting and receiving) and a receiver and processor to determine properties of the waves. Radio waves (pulsed or continuous) from the transmitter reflect off the waves and return to the receiver, giving information about the wave location and speed.

According to the invention, the sensor may scan the horizon and continuously measure the shape, speed and distance from the rig for each of the incoming or approaching waves. These measurements may be fed into a computer that calculates the time each of the waves will impact the rig. The computer can thus precisely predict into the future the waves that will impact the rig in a period of time corresponding to the scan distance for the sensor divided by the velocity of the waves. As an example; if the sensor can measure waves at 4000 meter distance, and the wave velocity is 20 meters/second, the wave predicting system can precisely predict an incoming wave 200 seconds or 3 minutes 20 seconds into the future (4000m/(20m/s)=200s). By combining the waves with the hydrodynamic model for the rig in a rig movement predictor unit, the rig movement can be calculated for each of the incoming wave combinations, thus giving an accurate prediction of the rig movement into the future.

It may be appropriate to arrange the sensor on top of a mast or tower on the floating drilling unit, in order to scan as far as possible into the horizon, to detect and measure the waves over a longer distance. The sensor may also scan any shorter distances than the horizon and generate measurements that can be used by the wave prediction unit to continuously calibrate the incoming waves that have been measured/detected previously. When the sensor is arranged in such a way that it is able to detect the incoming wave earlier than the time it takes to execute the weather critical operation sequence, the invention will be able to calculate the periods with safe operating envelopes to perform one or more predetermined operating sequences.

In a second aspect of the present invention it is provided a method of controlling a process automation system on a floating mobile offshore drilling unit. The method comprises receiving information of waves approaching the mobile offshore drilling unit from at least one sensor on the mobile offshore drilling unit. Predicting, in response to the received data, timing and physical characteristics of the approaching waves when reaching the mobile offshore drilling unit. Predicting, in response to the wave predictions, movement of the mobile offshore drilling unit, and enabling at least one operational sequence on board the mobile offshore drilling unit when the predicted movement of the mobile offshore drilling unit is within a predetermined safe operating envelope for the at least one operational sequence.

The sensor may be a radar adapted to scan over a horizon to detect and measure waves approaching the floating drilling unit. The safe operating envelopes are provided based on the actual detected and measured approaching waves.

The method may, following the enabling of the at least one operational sequence, comprising initiating the at least one operational sequence automatically.

The method may alternatively, or additionally, following the enabling of the at least one operational sequence, comprising presenting a ready signal to an operator prior to initiating the at least one operational sequence.

The method may comprise moving the drill string slowly up and down prior to the enabling of the at least one operational sequence.

In one embodiment, the method may further be comprising inputting the predicted movement of the mobile offshore drilling unit to a digital twin of representing an object or system the rig is interfacing or working on, and determining with the digital twin the safe operating envelope for the at least one operational sequence at any time based on the predicted movement of the mobile offshore drilling unit.

Brief Description of the drawings Following drawings are appended to facilitate the understanding of the invention. The drawings show embodiments of the invention, which will now be described by way of example only, where:

Fig. 1 is a schematic overview of an exemplary floating mobile offshore drilling unit according to the invention. Fig. 2 is a schematic overview of an exemplary floating mobile offshore drilling unit according to the invention.

Fig. 3 illustrates exemplary configurations of ready signals according to the invention.

Fig. 4 is a flow chart of an exemplary method according to the invention. Detailed description of the invention

In the following, different alternatives will be discussed in more detail with reference to the appended drawings. It should be understood, however, that the drawings are not intended to limit the scope of the invention to the subject-matter depicted in the drawings. The scope of the invention is defined in the appended claims.

In the exemplary embodiments, various features and details are shown in combination. The fact that several features are described with reference to a particular example should not be construed as implying that those features be necessity have to be included together in all the embodiments of the invention. Conversely, features that are described with reference to different embodiments should not be construed as mutually exclusive. As those skilled in the art will readily understand, embodiments that incorporate any subset of features described herein and that are not expressly interdependent have been contemplated by the inventor and are part of the intended disclosure. However, explicit descriptions of all such embodiments would not contribute to the understanding of the principles of the invention, and consequently some permutations have been omitted for the sake of simplicity. Figure 1 is a schematic overview of an exemplary floating Mobile Offshore Drilling Unit (MODU) 1, where the MODU 1 is used to perform different offshore operations, for instance drilling and well interventions, lifting and landing operations, or launch and recovery operations.

The MODU 1 comprises a derrick, a hoist system, a rotary system, a circulation system and at least one sensor 2 configured to detect and measure waves approaching the MODU. The at least one sensor 2 may be a radar, an infrared sensor, a lidar, a camera, or a combination of one or more such sensors. The at least one sensor 2 may be a stand-alone sensor, or it may be integrally combined in a wave prediction system 5. The sensor 2 may be adapted to scan over a horizon to detect and measure waves approaching the MODU such that a safe operating envelope may be provided based on the actual detected and measured approaching waves.

Now with additional reference to Figure 2, the wave prediction system 5 further comprises a wave prediction unit 6. The wave prediction unit 6 receives data from the at least one sensor 2. In response to the received data, the wave prediction unit 6 is configured to predict timing and/or physical characteristics of the approaching waves when reaching the mobile offshore drilling unit. A movement predictor unit 7 receives the predicted timing and/or physical characteristics of the waves from the wave prediction unit 6. In response to the received predicted timing and/or physical characteristics of the waves, the movement predictor unit 7 is configured to predict movement of the mobile offshore drilling unit 1. The predicted movement are based on the actual detected and measured approaching waves measured by the one or more sensors 2.

The mobile offshore drilling unit 1 also comprises at least one process automation system 8. The at least one process automation system 8 may automate drilling processes, lifting and landing processes, deployment and recovery processes or any other process that may be automated on the rig. Such process automation systems, as those skilled in the art will readily understand, may include information of the tasks and the time duration for executing such tasks together with information of challenges and problems that may arise and the time to solve them.

The process automation system 8 is configured to perform at least one operational sequence on board the mobile offshore drilling unit 1 within a predetermined safe operating envelope for the at least one operational sequence. The process automation system 8 receives the predicted movement of the mobile offshore drilling unit 1 from the movement predictor unit 7. The process automation system 8 having knowledge of both the predetermined safe operating envelope for the at least one operational sequence, and the predicted movement of the mobile offshore unit may then forecast when it is possible to perform the at least one operational sequence. The process automation system 8 is based on this knowledge configured to enable the at least one operational sequence when the predicted movement of the mobile offshore drilling unit 1 is within the predetermined safe operating envelope for the at least one operational sequence.

In one embodiment, the floating mobile offshore drilling unit 1, may further comprise a digital twin 9 of the drill string 3, and a borehole 4 that is being drilled. The digital twin 9 receives the predicted movement of the mobile offshore drilling unit 1 from the movement predictor unit 7. The digital twin 9 determines the safe operating envelope for the at least one operation sequence based on the predicted movement of the mobile offshore drilling unit 1 input to the digital twin 9. Being a virtual, digital equivalent to the physical drill string 3 and the borehole 4, the use of the digital twin 9 allows for more accurately calculating the safe operating envelope for the actual approaching wave.

In one embodiment, the process automation system 8 may initiate the at least one operational sequence automatically when within the predetermined safe operating envelope.

In another embodiment, the process automation system 8 may be configured to present a ready signal to an operator prior to initiating the at least one operational sequence. An operator may then initiate the operational sequence manually. The process automation system 8 may also present the ready signal to the operator prior to automatically initiating the at least one operational sequence when within the predetermined safe operating envelope embodiment.

Figure 3 illustrates exemplary configurations of different ready signals. Figures 3a and 3b show two lights 10, 11 and a timer 12. The two lights 10, 11 may have different colors, or have the color depending on preference or industry practices.

The timer 12 shows either the time to the next workable window, or the time left to safely perform operation. The function of the timer 12 changes when the light changes. In one example 3a, light 11 is green and light 10 is unlit, then the timer 12 show the seconds left to safely perform operation. In example 3b, light 11 is unlit and light 10 is red, then the timer 12 show the seconds until the next workable window. Figures 3c and 3d shows one light 10 and one timer 12. The one lights 10 may have different colors or have one color depending on preference or industry practices. As for examples 3a and 3b, the function of the timer 12 changes with the changes of light.

In a drilling application from a rig with active heave compensation of the draw work and top drive, when the rig movement is outside the safe operating limits, the drill string 3 will normally hang from the top drive in compensated mode meaning it will be stationary in the well. In such situation the present invention will allow the process automation system 8 to slowly move the drill string 3 up and down in a controlled manner while waiting for a time window where the drilling connection can be safely executed, i.e. prior to enabling the at least one operational sequence. This will avoid gelling of the drilling fluid, thus eliminating the pressure buildup from gel breaking when the drill string is set in slips and moves up and down with the rig heave.

Figure 4 illustrates a flow chart of an exemplary method of controlling a process automation system 8 on a floating mobile offshore drilling according to the invention. In a first step 13, information of waves approaching the mobile offshore drilling unit 1 is received from at least one sensor 2 on the mobile offshore drilling unit 1. In a next step 14, the predicted timing and/or physical characteristics of the approaching waves when reaching the mobile offshore drilling unit 1 is predicted in response to the received data. In a next step 15, movement of the mobile offshore drilling unit is predicted in response to the predicted timing and/or physical characteristics of the waves. In a next step 16, at least one operational sequence on board the mobile offshore drilling unit 1 is enabled when the predicted movement of the mobile offshore drilling unit is within a predetermined safe operating envelope for the at least one operational sequence. In one embodiment, the method further comprises a step 17, where the predicted movement of the mobile offshore drilling unit 1 is input to a digital twin 9 representing an object or system that the rig is interfacing or working on, and wherein the safe operating envelope for the at least one operational sequence is determined at any time based on the predicted movement of the mobile offshore drilling unit input to the digital twin.

Such a system or object or system may be the drill string 3 and the well 4 with its rock formation, cement, casing and fluids which all have varying mechanic, hydraulic and thermic characteristics. Another example object may be a supply vessel that moves in the waves and from its propulsion.

In one embodiment, following the enabling of the at least one operational sequence, the method may further comprise initiating the at least one operational sequence automatically.

In another embodiment, following the enabling of the at least one operational sequence, the method may further comprise presenting a ready signal to an operator prior to initiating the at least one operational sequence. An operator may then initiate the operational sequence manually. The ready signal may be presented to the to the operator prior to automatically initiating the at least one operational sequence when within the predetermined safe operating envelope.

In one embodiment, the method may further comprise moving the drill string 3 slowly up and down prior to the enabling of the at least one operational sequence.

The wave prediction unit 6, the movement predictor unit 7, the process automation system 8, and the digital twin 9 may be implemented in one or more computers having at least one processor or at least one memory. Custom programs, controlled by the wave prediction unit 6, the movement predictor unit 7, the process automation system 8, and the digital twin 9 are moved into and out of memory. These programs comprise at least the instructions to perform the method as described above.

Data transmitted and received by the at least sensor 2, the wave prediction unit 6, the movement predictor unit 7, the process automation system 8, and the digital twin 9 may be transmitted and received by known wired or wireless communication methods apparent to those skilled in the art.