NO20191269A1 - Floating mobile offshore drilling unit and method of controlling a process automation system - Google Patents

Floating mobile offshore drilling unit and method of controlling a process automation system Download PDF

Info

Publication number
NO20191269A1
NO20191269A1 NO20191269A NO20191269A NO20191269A1 NO 20191269 A1 NO20191269 A1 NO 20191269A1 NO 20191269 A NO20191269 A NO 20191269A NO 20191269 A NO20191269 A NO 20191269A NO 20191269 A1 NO20191269 A1 NO 20191269A1
Authority
NO
Norway
Prior art keywords
offshore drilling
drilling unit
mobile offshore
operational sequence
unit
Prior art date
Application number
NO20191269A
Inventor
Thomas Borsholm
Per Lund
Original Assignee
Odfjell Drilling As
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Odfjell Drilling As filed Critical Odfjell Drilling As
Priority to NO20191269A priority Critical patent/NO20191269A1/en
Priority to PCT/EP2020/080006 priority patent/WO2021078993A1/en
Priority to GB2206838.1A priority patent/GB2604502B/en
Publication of NO20191269A1 publication Critical patent/NO20191269A1/en
Priority to ZA2022/05231A priority patent/ZA202205231B/en

Links

Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B35/00—Vessels or similar floating structures specially adapted for specific purposes and not otherwise provided for
    • B63B35/44—Floating buildings, stores, drilling platforms, or workshops, e.g. carrying water-oil separating devices
    • B63B35/4413—Floating drilling platforms, e.g. carrying water-oil separating devices
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/08—Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods
    • E21B19/09—Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods specially adapted for drilling underwater formations from a floating support using heave compensators supporting the drill string
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B39/00—Equipment to decrease pitch, roll, or like unwanted vessel movements; Apparatus for indicating vessel attitude
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B79/00—Monitoring properties or operating parameters of vessels in operation
    • B63B79/10—Monitoring properties or operating parameters of vessels in operation using sensors, e.g. pressure sensors, strain gauges or accelerometers
    • B63B79/15—Monitoring properties or operating parameters of vessels in operation using sensors, e.g. pressure sensors, strain gauges or accelerometers for monitoring environmental variables, e.g. wave height or weather data
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B79/00—Monitoring properties or operating parameters of vessels in operation
    • B63B79/20—Monitoring properties or operating parameters of vessels in operation using models or simulation, e.g. statistical models or stochastic models
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B79/00—Monitoring properties or operating parameters of vessels in operation
    • B63B79/30—Monitoring properties or operating parameters of vessels in operation for diagnosing, testing or predicting the integrity or performance of vessels
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B79/00—Monitoring properties or operating parameters of vessels in operation
    • B63B79/40—Monitoring properties or operating parameters of vessels in operation for controlling the operation of vessels, e.g. monitoring their speed, routing or maintenance schedules
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
    • E21B19/004—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling supporting a riser from a drilling or production platform
    • E21B19/006—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling supporting a riser from a drilling or production platform including heave compensators
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/001—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor specially adapted for underwater drilling
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/12—Underwater drilling
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01C—MEASURING DISTANCES, LEVELS OR BEARINGS; SURVEYING; NAVIGATION; GYROSCOPIC INSTRUMENTS; PHOTOGRAMMETRY OR VIDEOGRAMMETRY
    • G01C13/00—Surveying specially adapted to open water, e.g. sea, lake, river or canal
    • G01C13/002—Measuring the movement of open water

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Ocean & Marine Engineering (AREA)
  • Combustion & Propulsion (AREA)
  • Chemical & Material Sciences (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Remote Sensing (AREA)
  • Radar, Positioning & Navigation (AREA)
  • General Physics & Mathematics (AREA)
  • Hydrology & Water Resources (AREA)
  • Probability & Statistics with Applications (AREA)
  • Atmospheric Sciences (AREA)
  • Architecture (AREA)
  • Civil Engineering (AREA)
  • Structural Engineering (AREA)
  • Earth Drilling (AREA)
  • Electrical Discharge Machining, Electrochemical Machining, And Combined Machining (AREA)
  • Automatic Tool Replacement In Machine Tools (AREA)

Description

Technical field
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 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.
In view of the above, the aim of the present invention is to provide a floating mobile offshore drilling unit, and a method of controlling such a floating mobile offshore drilling unit, that solves or at least mitigate one or more of the above-mentioned problems related to the use of prior art floating mobile offshore drilling units.
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 waves approaching the mobile offshore drilling unit, and a wave prediction unit 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 historical data of waves and weather conditions and their impact to the mobile and offshore drilling unit. 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, a motion recording unit, a gyro, an accelerometer, a depth sensor, an infrared sensor, a lidar, a camera, a wind sensor or a GPS or a combination thereof.
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 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 circulat ion system and at least one sensor 2 configured to detect waves approaching the MODU. The at least one sensor 2 may be a radar, a motion recording unit, a gyro, an accelerometer, a depth sensor, an infrared sensor, a lidar, a camera, a wind sensor, a GPS 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.
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 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 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.

Claims (12)

1. Floating mobile offshore drilling unit (1) comprising:
- a wave prediction system comprising:
- at least one sensor (2) configured to detect waves approaching the mobile offshore drilling unit (1), and
- a wave prediction unit for receiving data from the at least one sensor, the wave prediction unit 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;
- a movement predictor unit for receiving the 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;
- 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; and
wherein the at least one 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.
2. The floating mobile offshore drilling unit of claim 1, wherein the at least one process automation system 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 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 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 is a radar, a motion recording unit, a gyro, an accelerometer, a depth sensor, an infrared sensor, a lidar, a camera, a wind sensor or a GPS, or a combination thereof.
8. Method of controlling a process automation system 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 on the mobile offshore drilling unit,
- predicting, in response to the received data, timing and/or physical characteristics of the approaching waves when reaching the mobile offshore drilling unit,
- 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 when the predicted movement of the mobile offshore drilling unit is within a predetermined safe operating envelope for the at least one operational sequence.
9. The method of claim 8, wherein following the enabling of the at least one operational sequence, the method further comprising initiating the at least one operational sequence automatically.
10. The method of any of claims 8 or 9, 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.
11. The method of any of claims 8 – 10, wherein the method further comprises moving a drill string slowly up and down prior to the enabling of the at least one operational sequence.
12. The method of any of claims 8 - 11, 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.
NO20191269A 2019-10-24 2019-10-24 Floating mobile offshore drilling unit and method of controlling a process automation system NO20191269A1 (en)

Priority Applications (4)

Application Number Priority Date Filing Date Title
NO20191269A NO20191269A1 (en) 2019-10-24 2019-10-24 Floating mobile offshore drilling unit and method of controlling a process automation system
PCT/EP2020/080006 WO2021078993A1 (en) 2019-10-24 2020-10-26 A mobile offshore drilling unit and method of controlling a process automation system
GB2206838.1A GB2604502B (en) 2019-10-24 2020-10-26 A mobile offshore drilling unit and method of controlling a process automation system
ZA2022/05231A ZA202205231B (en) 2019-10-24 2022-05-11 A mobile offshore drilling unit and method of controlling a process automation system

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
NO20191269A NO20191269A1 (en) 2019-10-24 2019-10-24 Floating mobile offshore drilling unit and method of controlling a process automation system

Publications (1)

Publication Number Publication Date
NO20191269A1 true NO20191269A1 (en) 2021-04-26

Family

ID=73014525

Family Applications (1)

Application Number Title Priority Date Filing Date
NO20191269A NO20191269A1 (en) 2019-10-24 2019-10-24 Floating mobile offshore drilling unit and method of controlling a process automation system

Country Status (4)

Country Link
GB (1) GB2604502B (en)
NO (1) NO20191269A1 (en)
WO (1) WO2021078993A1 (en)
ZA (1) ZA202205231B (en)

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP4098542A1 (en) * 2021-06-02 2022-12-07 Siemens Gamesa Renewable Energy A/S Estimating a sea state of an offshore wind turbine

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6064924A (en) * 1996-12-04 2000-05-16 Lockheed Martin Corporation Method and system for predicting ship motion or the like to assist in helicopter landing
US20140114509A1 (en) * 2012-10-24 2014-04-24 John D. Venables Predictive Sea State Mapping for Ship Motion Control
JP2017021029A (en) * 2015-07-10 2017-01-26 国立研究開発法人 海上・港湾・航空技術研究所 Wave measuring device and floating body comprising wave measuring device
US20180081054A1 (en) * 2016-09-16 2018-03-22 Applied Physical Sciences Corp. Systems and methods for wave sensing and ship motion forecasting using multiple radars
US10323474B2 (en) * 2015-07-07 2019-06-18 Halliburton Energy Services, Inc. Heave compensated managed pressure drilling

Family Cites Families (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
JP5120342B2 (en) * 2009-06-18 2013-01-16 ソニー株式会社 Manufacturing method of semiconductor package
US10920389B2 (en) * 2017-08-02 2021-02-16 Rowan Companies, Inc. Multi-stage coming off location technology

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6064924A (en) * 1996-12-04 2000-05-16 Lockheed Martin Corporation Method and system for predicting ship motion or the like to assist in helicopter landing
US20140114509A1 (en) * 2012-10-24 2014-04-24 John D. Venables Predictive Sea State Mapping for Ship Motion Control
US10323474B2 (en) * 2015-07-07 2019-06-18 Halliburton Energy Services, Inc. Heave compensated managed pressure drilling
JP2017021029A (en) * 2015-07-10 2017-01-26 国立研究開発法人 海上・港湾・航空技術研究所 Wave measuring device and floating body comprising wave measuring device
US20180081054A1 (en) * 2016-09-16 2018-03-22 Applied Physical Sciences Corp. Systems and methods for wave sensing and ship motion forecasting using multiple radars

Also Published As

Publication number Publication date
GB2604502B (en) 2023-09-06
ZA202205231B (en) 2024-01-31
WO2021078993A1 (en) 2021-04-29
GB2604502A (en) 2022-09-07

Similar Documents

Publication Publication Date Title
US11047223B2 (en) Interface and integration method for external control of drilling control system
MX2012009937A (en) Method for calibrating a hydraulic model.
MX2012009938A (en) Wellbore interval densities.
MX2012009936A (en) Methods for evaluating inflow and outflow in a subterraean wellbore.
GB2494053A (en) A method for computing an interval cuttings density
WO2016040310A1 (en) Systems and methods for detection of an influx during drilling operations
US11364979B2 (en) Drilling or work-over rig comprising an operational control and/or state unit and a computer-implemented method of providing operational control and/or state
CN110462159B (en) Joint identification system
NO20191269A1 (en) Floating mobile offshore drilling unit and method of controlling a process automation system
US20190078401A1 (en) Tool joint positioning
RU2244117C2 (en) Method for controlling operations in well and system for well-drilling
KR20190131080A (en) Vertical lift rotary table
EP3438350B1 (en) Subsea deployment monitoring system
GB2494960A (en) Calibrating a wellbore hydraulic model
BR112018073967B1 (en) METHOD OF CONTROLLING A WELL DRILLING PROCESS AND DRILLING CONTROL SYSTEM