EP4264012A1 - Réglages dynamiques de limites de paramètres de forage - Google Patents

Réglages dynamiques de limites de paramètres de forage

Info

Publication number
EP4264012A1
EP4264012A1 EP21908051.2A EP21908051A EP4264012A1 EP 4264012 A1 EP4264012 A1 EP 4264012A1 EP 21908051 A EP21908051 A EP 21908051A EP 4264012 A1 EP4264012 A1 EP 4264012A1
Authority
EP
European Patent Office
Prior art keywords
drilling
response
drilling parameter
window
new
Prior art date
Legal status (The legal status 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 status listed.)
Pending
Application number
EP21908051.2A
Other languages
German (de)
English (en)
Inventor
James Belaskie
Robert HUGHES, Jr.
Nathaniel Wicks
James Foley
Rafael GUEDES DE CARVALHO
Teddy Cheryl Michael NKOUNKOU
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Services Petroliers Schlumberger SA
Geoquest Systems BV
Original Assignee
Services Petroliers Schlumberger SA
Geoquest Systems BV
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 Services Petroliers Schlumberger SA, Geoquest Systems BV filed Critical Services Petroliers Schlumberger SA
Publication of EP4264012A1 publication Critical patent/EP4264012A1/fr
Pending legal-status Critical Current

Links

Classifications

    • 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
    • E21B7/04—Directional drilling
    • E21B7/06—Deflecting the direction of boreholes
    • 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
    • E21B45/00—Measuring the drilling time or rate of penetration
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or 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
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional 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
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/20—Computer models or simulations, e.g. for reservoirs under production, drill bits

Definitions

  • Certain drilling parameters on a drilling rig can be controlled directly, such as block speed up or down, pump stroke rate, surface drillstring rotation speed or revolutions per minute (RPM).
  • RPM revolutions per minute
  • Increasing or decreasing these drilling parameters results in responses in the equipment and the well.
  • the response to RPM includes drillstring torque
  • a response to block speed changes is a change in hookload and surface weight
  • a response to pump stroke rate changes includes changes in standpipe pressure.
  • Drilling parameters typically need to be kept within limits.
  • Some drilling parameter limits are hard limits. Exceeding the hard limits may result in damage to the equipment and pose health, environmental, and safety risks.
  • a drillstring torque hard limit may set a value which, if exceeded, could cause damage to the top drive or the drill pipe.
  • Other drilling parameter limits are sectional limits. Sectional limits may be values that, based on experience, simulation, analysis, or some combination of the above, the team believes will provide the best average performance while drilling that wellbore section. Summary
  • Drilling automation and recommendation systems generally try to adhere to both hard limits and sectional limits in all circumstances. While doing so often results in good performance, there are circumstances in which better results may be achieved by exceeding certain limits. For example, there are conditions where, while drilling, certain non-hard sectional limits may be temporarily exceeded to better handle a particular event or challenge. For example, stick-slip vibrations may damage the bit and the topdrive. Mitigating stick slip may involve reducing the weight on bit and increasing the RPM. However, the speed may already be close to the boundary in a given section. An ‘overdrive’ speed, for example, of 20-25 RPM above a sectional limit, may be acceptable temporarily to mitigate stick slip. This may allow the stick slip event to mitigated more quickly. Once the stick slip event has been successfully mitigated, the RPM may then be reduced back below the sectional limit.
  • overdrive for example, of 20-25 RPM above a sectional limit
  • This document discloses a method, a non-transitory, tangible computer-readable storage medium, and a system for dynamically adjusting drilling parameters during a drilling operation.
  • the method involves receiving, in real time, drilling parameter measurements during a drilling operation and response measurements during the drilling operation.
  • the approach may involve determining whether the response measurement is within a response window that defines a desired lower limit and a desired upper limit for the response measurement.
  • a system determines a new drilling parameter value that will increase the response measurement.
  • the system compares the new drilling parameter value with a sectional limits and the hard limits for the drilling parameter. If the drilling parameter value is above the sectional limit and below the hard limit, the system may increase the upper value of the drilling parameter window for the drilling parameter to the new drilling parameter value.
  • the approach may further comprising instructions for automatically increasing the drilling parameter to the new drilling parameter value that will increase the response measurement.
  • the approach may also involve monitoring the response measurement after increasing the drilling parameter to the new drilling parameter value, determining that the response measurement is stabilizing within the response window; and resetting the upper value of the drilling parameter window to the sectional limit for the drilling parameter.
  • the approach is used to manage the differential pressure in a directional drilling operation.
  • the approach may involve measuring, in real time, the differential pressure across a motor of a bottom hole assembly and the rate of penetration of the bottom hole assembly during the directional drilling operation.
  • the approach may involve determining whether the differential pressure is within a predefined differential pressure window specifying a lower limit for the differential pressure and an upper limit for the differential pressure.
  • the system may determine a new rate of penetration value that will increase the differential pressure, compare the new rate of penetration value with the hard limits and sectional limits for rate of penetration and, if the new rate of penetration value is above the sectional limit and below the hard limit, increase the upper value of a rate of penetration window to the new rate of penetration value.
  • Figure 1 illustrates an example of a system that includes various management components to manage various aspects of a geologic environment, according to an embodiment.
  • Figure 2 illustrates an example of a drilling system that can be used to drill a well.
  • Figure 3 illustrates a flowchart of a method for adjusting a drilling parameter.
  • Figure 4 illustrates a flowchart of a method for adjusting rate of penetration.
  • Figure 5A illustrates one embodiment of a drilling response measurement and a drilling parameter measurement.
  • Figure 5B illustrates one embodiment of a drilling response measurement and a drilling parameter measurement and dynamic adjustments of the drilling parameter values.
  • Figure 6 illustrates a schematic view of a computing system, according to an embodiment. Detailed Description
  • first”, “second”, etc. may be used herein to describe various elements, these terms are used to distinguish one element from another.
  • a first object or step could be termed a second object or step, and, similarly, a second object or step could be termed a first object or step, without departing from the scope of the present disclosure.
  • the first object or step, and the second object or step are both, objects or steps, respectively, but they are not to be considered the same object or step.
  • FIG 1 illustrates an example of a system 100 that includes various management components 110 to manage various aspects of a geologic environment 150 (e.g., an environment that includes a sedimentary basin, a reservoir 151, one or more faults 153-1, one or more geobodies 153-2, etc.).
  • the management components 110 may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment 150.
  • further information about the geologic environment 150 may become available as feedback 160 (e.g., optionally as input to one or more of the management components 110).
  • the management components 110 include a seismic data component 112, an additional information component 114 (e.g., well/logging data), a processing component 116, a simulation component 120, an attribute component 130, an analysis/visualization component 142 and a workflow component 144.
  • seismic data and other information provided per the components 112 and 114 may be input to the simulation component 120.
  • the simulation component 120 may rely on entities 122.
  • Entities 122 may include earth entities or geological objects such as wells, surfaces, bodies, reservoirs, etc.
  • the entities 122 can include virtual representations of actual physical entities that are reconstructed for purposes of simulation.
  • the entities 122 may include entities based on data acquired via sensing, observation, etc. (e.g., the seismic data 112 and other information 114).
  • An entity may be characterized by one or more properties (e.g., a geometrical pillar grid entity of an earth model may be characterized by a porosity property). Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.
  • the simulation component 120 may operate in conjunction with a software framework such as an object-based framework.
  • entities may include entities based on pre-defined classes to facilitate modeling and simulation.
  • object-based framework is the MICROSOFT® .NET® framework (Redmond, Washington), which provides a set of extensible object classes.
  • .NET® framework an object class encapsulates a module of reusable code and associated data structures.
  • Object classes can be used to instantiate object instances for use in by a program, script, etc.
  • borehole classes may define objects for representing boreholes based on well data.
  • the simulation component 120 may process information to conform to one or more attributes specified by the attribute component 130, which may include a library of attributes. Such processing may occur prior to input to the simulation component 120 (e.g., consider the processing component 116). As an example, the simulation component 120 may perform operations on input information based on one or more attributes specified by the attribute component 130. In an example embodiment, the simulation component 120 may construct one or more models of the geologic environment 150, which may be relied on to simulate behavior of the geologic environment 150 (e.g., responsive to one or more acts, whether natural or artificial). In the example of Figure 1, the analysis/visualization component 142 may allow for interaction with a model or model-based results (e.g., simulation results, etc.). As an example, output from the simulation component 120 may be input to one or more other workflows, as indicated by a workflow component 144.
  • the simulation component 120 may include one or more features of a simulator such as the ECLIPSETM reservoir simulator (Schlumberger Limited, Houston Texas), the INTERSECTTM reservoir simulator (Schlumberger Limited, Houston Texas), etc.
  • a simulation component, a simulator, etc. may include features to implement one or more meshless techniques (e.g., to solve one or more equations, etc.).
  • a reservoir or reservoirs may be simulated with respect to one or more enhanced recovery techniques (e.g., consider a thermal process such as SAGD, etc.).
  • the management components 110 may include features of a commercially available framework such as the PETREL® seismic to simulation software framework (Schlumberger Limited, Houston, Texas).
  • the PETREL® framework provides components that allow for optimization of exploration and development operations.
  • the PETREL® framework includes seismic to simulation software components that can output information for use in increasing reservoir performance, for example, by improving asset team productivity.
  • various professionals e.g., geophysicists, geologists, and reservoir engineers
  • Such a framework may be considered an application and may be considered a data- driven application (e.g., where data is input for purposes of modeling, simulating, etc.).
  • various aspects of the management components 110 may include add-ons or plug-ins that operate according to specifications of a framework environment.
  • a framework environment e.g., a commercially available framework environment marketed as the OCEAN® framework environment (Schlumberger Limited, Houston, Texas) allows for integration of addons (or plug-ins) into a PETREL® framework workflow.
  • the OCEAN® framework environment leverages .NET® tools (Microsoft Corporation, Redmond, Washington) and offers stable, user- friendly interfaces for efficient development.
  • various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).
  • API application programming interface
  • Figure 1 also shows an example of a framework 170 that includes a model simulation layer 180 along with a framework services layer 190, a framework core layer 195 and a modules layer 175.
  • the framework 170 may include the commercially available OCEAN® framework where the model simulation layer 180 is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.
  • the PETREL® software may be considered a data-driven application.
  • the PETREL® software can include a framework for model building and visualization.
  • a framework may include features for implementing one or more mesh generation techniques.
  • a framework may include an input component for receipt of information from interpretation of seismic data, one or more attributes based at least in part on seismic data, log data, image data, etc.
  • Such a framework may include a mesh generation component that processes input information, optionally in conjunction with other information, to generate a mesh.
  • the model simulation layer 180 may provide domain objects 182, act as a data source 184, provide for rendering 186 and provide for various user interfaces 188.
  • Rendering 186 may provide a graphical environment in which applications can display their data while the user interfaces 188 may provide a common look and feel for application user interface components.
  • the domain objects 182 can include entity objects, property objects and optionally other objects.
  • Entity objects may be used to geometrically represent wells, surfaces, bodies, reservoirs, etc.
  • property objects may be used to provide property values as well as data versions and display parameters.
  • an entity object may represent a well where a property object provides log information as well as version information and display information (e.g., to display the well as part of a model).
  • data may be stored in one or more data sources (or data stores, generally physical data storage devices), which may be at the same or different physical sites and accessible via one or more networks.
  • the model simulation layer 180 may be configured to model projects. As such, a particular project may be stored where stored project information may include inputs, models, results and cases. Thus, upon completion of a modeling session, a user may store a project. At a later time, the project can be accessed and restored using the model simulation layer 180, which can recreate instances of the relevant domain objects.
  • the geologic environment 150 may include layers (e.g., stratification) that include a reservoir 151 and one or more other features such as the fault 153-1, the geobody 153-2, etc.
  • the geologic environment 150 may be outfitted with any of a variety of sensors, detectors, actuators, etc.
  • equipment 152 may include communication circuitry to receive and to transmit information with respect to one or more networks 155.
  • Such information may include information associated with downhole equipment 154, which may be equipment to acquire information, to assist with resource recovery, etc.
  • Other equipment 156 may be located remote from a well site and include sensing, detecting, emitting or other circuitry.
  • Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.
  • one or more satellites may be provided for purposes of communications, data acquisition, etc.
  • Figure 1 shows a satellite in communication with the network 155 that may be configured for communications, noting that the satellite may additionally or instead include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).
  • imagery e.g., spatial, spectral, temporal, radiometric, etc.
  • Figure 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159.
  • equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159.
  • a well in a shale formation may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.
  • a well may be drilled for a reservoir that is laterally extensive.
  • lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop a laterally extensive reservoir (e.g., via fracturing, injecting, extracting, etc.).
  • the equipment 157 and/or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.
  • a workflow may be a process that includes a number of worksteps.
  • a workstep may operate on data, for example, to create new data, to update existing data, etc.
  • a may operate on one or more inputs and create one or more results, for example, based on one or more algorithms.
  • a system may include a workflow editor for creation, editing, executing, etc. of a workflow.
  • the workflow editor may provide for selection of one or more predefined worksteps, one or more customized worksteps, etc.
  • a workflow may be a workflow implementable in the PETREL® software, for example, that operates on seismic data, seismic attribute(s), etc.
  • a workflow may be a process implementable in the OCEAN® framework.
  • a workflow may include one or more worksteps that access a module such as a plug-in (e.g., external executable code, etc.).
  • Fig. 2 shows an example of a wellsite system 200 (e.g., at a wellsite that may be onshore or offshore).
  • the wellsite system 200 can include a mud tank 201 for holding mud and other material (e.g., where mud can be a drilling fluid), a suction line 203 that serves as an inlet to a mud pump 204 for pumping mud from the mud tank 201 such that mud flows to a vibrating hose 206, a drawworks 207 for winching drill line or drill lines 212, a standpipe 208 that receives mud from the vibrating hose 206, a kelly hose 209 that receives mud from the standpipe 208, a gooseneck or goosenecks 210, a traveling block 211, a crown block 213 for carrying the traveling block 211 via the drill line or drill lines 212 (see, e.g., the crown block 173 of Fig.
  • a derrick 214 see, e.g., the derrick 172 of Fig. 1
  • a kelly 218 or a top drive 240 see, e.g., the derrick 172 of Fig. 1
  • a kelly drive bushing 219 a rotary table 220
  • a drill floor 221, a bell nipple 222 one or more blowout preventors (BOPs) 223, a drillstring 225, a drill bit 226, a casing head 227 and a flow pipe 228 that carries mud and other material to, for example, the mud tank 201.
  • BOPs blowout preventors
  • a borehole 232 is formed in subsurface formations 230 by rotary drilling; noting that various example embodiments may also use one or more directional drilling techniques, equipment, etc.
  • the drillstring 225 is suspended within the borehole 232 and has a drillstring assembly 250 that includes the drill bit 226 at its lower end.
  • the drillstring assembly 250 may be a bottom hole assembly (BHA).
  • the wellsite system 200 can provide for operation of the drillstring 225 and other operations. As shown, the wellsite system 200 includes the traveling block 211 and the derrick 214 positioned over the borehole 232. As mentioned, the wellsite system 200 can include the rotary table 220 where the drillstring 225 pass through an opening in the rotary table 220.
  • the wellsite system 200 can include the kelly 218 and associated components, etc., or a top drive 240 and associated components.
  • the kelly 218 may be a square or hexagonal metal/alloy bar with a hole drilled therein that serves as a mud flow path.
  • the kelly 218 can be used to transmit rotary motion from the rotary table 220 via the kelly drive bushing 219 to the drillstring 225, while allowing the drillstring 225 to be lowered or raised during rotation.
  • the kelly 218 can pass through the kelly drive bushing 219, which can be driven by the rotary table 220.
  • the rotary table 220 can include a master bushing that operatively couples to the kelly drive bushing 219 such that rotation of the rotary table 220 can turn the kelly drive bushing 219 and hence the kelly 218.
  • the kelly drive bushing 219 can include an inside profile matching an outside profile (e.g., square, hexagonal, etc.) of the kelly 218; however, with slightly larger dimensions so that the kelly 218 can freely move up and down inside the kelly drive bushing 219.
  • the top drive 240 can provide functions performed by a kelly and a rotary table.
  • the top drive 240 can turn the drillstring 225.
  • the top drive 240 can include one or more motors (e.g., electric and/or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring 225 itself.
  • the top drive 240 can be suspended from the traveling block 211, so the rotary mechanism is free to travel up and down the derrick 214.
  • a top drive 240 may allow for drilling to be performed with more joint stands than a kelly/rotary table approach.
  • the mud tank 201 can hold mud, which can be one or more types of drilling fluids.
  • mud can be one or more types of drilling fluids.
  • a wellbore may be drilled to produce fluid, inject fluid or both (e.g., hydrocarbons, minerals, water, etc.).
  • the drillstring 225 (e.g., including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit 226 at the lower end thereof.
  • the mud may be pumped by the pump 204 from the mud tank 201 (e.g., or other source) via a the lines 206, 208 and 209 to a port of the kelly 218 or, for example, to a port of the top drive 240.
  • the mud can then flow via a passage (e.g., or passages) in the drillstring 225 and out of ports located on the drill bit 226 (see, e.g., a directional arrow).
  • a passage e.g., or passages
  • the mud can then circulate upwardly through an annular region between an outer surface(s) of the drill string 225 and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows.
  • the mud lubricates the drill bit 226 and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the mud (e.g., and cuttings) may be returned to the mud tank 201, for example, for recirculation (e.g., with processing to remove cuttings, etc.).
  • the mud pumped by the pump 204 into the drillstring 225 may, after exiting the drillstring 225, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drillstring 225 and surrounding wall(s) (e.g., borehole, casing, etc.). A reduction in friction may facilitate advancing or retracting the drillstring 225.
  • the entire drillstring 225 may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drillstring, etc.
  • tripping the act of pulling a drillstring out of a hole or replacing it in a hole is referred to as tripping.
  • a trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.
  • the mud can be pumped by the pump 204 into a passage of the drillstring 225 and, upon filling of the passage, the mud may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.
  • mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the mud to create an acoustic wave or waves upon which information may modulated.
  • information from downhole equipment e.g., one or more modules of the drillstring 225
  • telemetry equipment may operate via transmission of energy via the drillstring 225 itself.
  • a signal generator that imparts coded energy signals to the drillstring 225 and repeaters that may receive such energy and repeat it to further transmit the coded energy signals (e.g., information, etc.).
  • the drillstring 225 may be fitted with telemetry equipment 252 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the mud, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses.
  • telemetry equipment 252 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator
  • an alternator may be coupled to the aforementioned drive shaft where the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.
  • an uphole control and/or data acquisition system 262 may include circuitry to sense pressure pulses generated by telemetry equipment 252 and, for example, communicate sensed pressure pulses or information derived therefrom for process, control, etc.
  • the assembly 250 of the illustrated example includes a logging-while-drilling (LWD) module 254, a measurement-while-drilling (MWD) module 256, an optional module 258, a rotarysteerable system (RSS) and/or motor 260, and the drill bit 226.
  • LWD logging-while-drilling
  • MWD measurement-while-drilling
  • RSS rotarysteerable system
  • motor 260 rotarysteerable motor 260
  • drill bit 226 Such components or modules may be referred to as tools where a drillstring can include a plurality of tools.
  • a RSS it involves technology utilized for directional drilling.
  • Directional drilling involves drilling into the Earth to form a deviated bore such that the trajectory of the bore is not vertical; rather, the trajectory deviates from vertical along one or more portions of the bore.
  • drilling can commence with a vertical portion and then deviate from vertical such that the bore is aimed at the target and, eventually, reaches the target.
  • Directional drilling may be implemented where a target may be inaccessible from a vertical location at the surface of the Earth, where material exists in the Earth that may impede drilling or otherwise be detrimental (e.g., consider a salt dome, etc.), where a formation is laterally extensive (e.g., consider a relatively thin yet laterally extensive reservoir), where multiple bores are to be drilled from a single surface bore, where a relief well is desired, etc.
  • a target may be inaccessible from a vertical location at the surface of the Earth, where material exists in the Earth that may impede drilling or otherwise be detrimental (e.g., consider a salt dome, etc.), where a formation is laterally extensive (e.g., consider a relatively thin yet laterally extensive reservoir), where multiple bores are to be drilled from a single surface bore, where a relief well is desired, etc.
  • a mud motor can present some challenges depending on factors such as rate of penetration (ROP), transferring weight to a bit (e.g., weight on bit, WOB) due to friction, etc.
  • a mud motor can be a positive displacement motor (PDM) that operates to drive a bit (e.g., during directional drilling, etc.).
  • PDM operates as drilling fluid is pumped through it where the PDM converts hydraulic power of the drilling fluid into mechanical power to cause the bit to rotate.
  • a PDM may operate in a combined rotating mode where surface equipment is utilized to rotate a bit of a drillstring (e.g., a rotary table, a top drive, etc.) by rotating the entire drillstring and where drilling fluid is utilized to rotate the bit of the drillstring.
  • a surface RPM SRPM
  • SRPM surface RPM
  • bit RPM can be determined or estimated as a sum of the SRPM and the mud motor RPM, assuming the SRPM and the mud motor RPM are in the same direction.
  • a PDM mud motor can operate in a so-called sliding mode, when the drillstring is not rotated from the surface.
  • a bit RPM can be determined or estimated based on the RPM of the mud motor.
  • a RSS can drill directionally where there is continuous rotation from surface equipment, which can alleviate the sliding of a steerable motor (e.g., a PDM).
  • a RSS may be deployed when drilling directionally (e.g., deviated, horizontal, or extended-reach wells).
  • a RSS can aim to minimize interaction with a borehole wall, which can help to preserve borehole quality.
  • a RSS can aim to exert a relatively consistent side force akin to stabilizers that rotate with the drillstring or orient the bit in the desired direction while continuously rotating at the same number of rotations per minute as the drillstring.
  • the LWD module 254 may be housed in a suitable type of drill collar and can contain one or a plurality of selected types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, for example, as represented at by the module 256 of the drillstring assembly 250. Where the position of an LWD module is mentioned, as an example, it may refer to a module at the position of the LWD module 254, the module 256, etc.
  • An LWD module can include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the illustrated example, the LWD module 254 may include a seismic measuring device.
  • the MWD module 256 may be housed in a suitable type of drill collar and can contain one or more devices for measuring characteristics of the drillstring 225 and the drill bit 226.
  • the MWD tool 254 may include equipment for generating electrical power, for example, to power various components of the drillstring 225.
  • the MWD tool 254 may include the telemetry equipment 252, for example, where the turbine impeller can generate power by flow of the mud; it being understood that other power and/or battery systems may be employed for purposes of powering various components.
  • the MWD module 256 may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.
  • Fig. 2 also shows some examples of types of holes that may be drilled. For example, consider a slant hole 272, an S-shaped hole 274, a deep inclined hole 276 and a horizontal hole 278.
  • a drilling operation can include directional drilling where, for example, at least a portion of a well includes a curved axis.
  • a radius that defines curvature where an inclination with regard to the vertical may vary until reaching an angle between about 30 degrees and about 60 degrees or, for example, an angle to about 90 degrees or possibly greater than about 90 degrees.
  • a directional well can include several shapes where each of the shapes may aim to meet particular operational demands.
  • a drilling process may be performed on the basis of information as and when it is relayed to a drilling engineer.
  • inclination and/or direction may be modified based on information received during a drilling process.
  • deviation of a bore may be accomplished in part by use of a downhole motor and/or a turbine.
  • a motor for example, a drillstring can include a positive displacement motor (PDM).
  • PDM positive displacement motor
  • a system may be a steerable system and include equipment to perform method such as geosteering.
  • a steerable system can be or include an RSS.
  • a steerable system can include a PDM or of a turbine on a lower part of a drillstring which, just above a drill bit, a bent sub can be mounted.
  • MWD equipment that provides real time or near real time data of interest (e.g., inclination, direction, pressure, temperature, real weight on the drill bit, torque stress, etc.) and/or LWD equipment may be installed.
  • LWD equipment can make it possible to send to the surface various types of data of interest, including for example, geological data (e.g., gamma ray log, resistivity, density and sonic logs, etc.).
  • geological data e.g., gamma ray log, resistivity, density and sonic logs, etc.
  • the coupling of sensors providing information on the course of a well trajectory, in real time or near real time, with, for example, one or more logs characterizing the formations from a geological viewpoint, can allow for implementing a geosteering method. Such a method can include navigating a subsurface environment, for example, to follow a desired route to reach a desired target or targets.
  • a drillstring can include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth and shocks; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bend joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and/or responding to one or more of inclination, resistivity and gamma ray related phenomena.
  • ADN azimuthal density neutron
  • MWD for measuring inclination, azimuth and shocks
  • CDR compensated dual resistivity
  • geosteering can include intentional directional control of a wellbore based on results of downhole geological logging measurements in a manner that aims to keep a directional wellbore within a desired region, zone (e.g., a pay zone), etc.
  • geosteering may include directing a wellbore to keep the wellbore in a particular section of a reservoir, for example, to minimize gas and/or water breakthrough and, for example, to maximize economic production from a well that includes the wellbore.
  • the wellsite system 200 can include one or more sensors 264 that are operatively coupled to the control and/or data acquisition system 262.
  • a sensor or sensors may be at surface locations.
  • a sensor or sensors may be at downhole locations.
  • a sensor or sensors may be at one or more remote locations that are not within a distance of the order of about one hundred meters from the wellsite system 200.
  • a sensor or sensor may be at an offset wellsite where the wellsite system 200 and the offset wellsite are in a common field (e.g., oil and/or gas field).
  • one or more of the sensors 264 can be provided for tracking pipe, tracking movement of at least a portion of a drillstring, etc.
  • the system 200 can include one or more sensors 266 that can sense and/or transmit signals to a fluid conduit such as a drilling fluid conduit (e.g., a drilling mud conduit).
  • a fluid conduit such as a drilling fluid conduit (e.g., a drilling mud conduit).
  • the one or more sensors 266 can be operatively coupled to portions of the standpipe 208 through which mud flows.
  • a downhole tool can generate pulses that can travel through the mud and be sensed by one or more of the one or more sensors 266.
  • the downhole tool can include associated circuitry such as, for example, encoding circuitry that can encode signals, for example, to reduce demands as to transmission.
  • circuitry at the surface may include decoding circuitry to decode encoded information transmitted at least in part via mud-pulse telemetry.
  • circuitry at the surface may include encoder circuitry and/or decoder circuitry and circuitry downhole may include encoder circuitry and/or decoder circuitry.
  • the system 200 can include a transmitter that can generate signals that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.
  • mud e.g., drilling fluid
  • stuck can refer to one or more of varying degrees of inability to move or remove a drill string from a bore.
  • a stuck condition it might be possible to rotate pipe or lower it back into a bore or, for example, in a stuck condition, there may be an inability to move the drillstring axially in the bore, though some amount of rotation may be possible.
  • a stuck condition there may be an inability to move at least a portion of the drillstring axially and rotationally.
  • stuck pipe this can refer to a portion of a drillstring that cannot be rotated or moved axially.
  • a condition referred to as “differential sticking” can be a condition whereby the drillstring cannot be moved (e.g., rotated or reciprocated) along the axis of the bore. Differential sticking may occur when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking can have time and financial cost.
  • a sticking force can be a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking pipe as can a high differential pressure applied over a small area.
  • a condition referred to as “mechanical sticking” can be a condition where limiting or prevention of motion of the drillstring by a mechanism other than differential pressure sticking occurs.
  • Mechanical sticking can be caused, for example, by one or more of junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus.
  • Figure 3 illustrates one embodiment of a method for dynamically adjusting drilling parameters during a drilling operation.
  • the method involves receiving 302 drilling parameter measurements in real time during a drilling operation.
  • a drilling parameter refers to a parameter that can be changed directly or indirectly and that creates a measurable response.
  • the drilling parameters may be for surface equipment, a downhole tool, or both.
  • the drilling parameters being measured may be rate of penetration, surface drillstring rotation speed, block speed, pump stroke rate, others, or a combination of different drilling parameters being measured.
  • the method may also involve receiving 304 response measurements during the drilling operation.
  • responses are changes in values that result from changes to the drilling parameters.
  • an example includes changes in drillstring torque in response to changes in RPM.
  • Another example is a change to differential pressure across a motor in response to changes in rate of penetration (ROP).
  • the response measurement may be, for example, drillstring torque, hookload, weight on bit, differential pressure, or a combination thereof.
  • the method may involve determining 306 whether the response measurement is within a response window that defines a desired lower limit and a desired upper limit for the response measurement. While the response measurement is within the response window, the method may involve continuously monitoring the drilling parameters and the responses. In response to determining that the response measurement is below the desired lower limit, the method may involve taking corrective action to return the response measurement to the window. In certain embodiments, the method may trigger the corrective action even when the response measurement is still within the response window if it determines that the response measurement is trending downwards towards the desired lower limit of the response window.
  • the method involves determining a rate of change of the response measurement and estimating the amount of time it will take for a change in a drilling parameter to impact the response measurement.
  • the method may trigger changes to the drilling parameter while there is sufficient time to impact the response measurement and keep it within the response window.
  • the approach involves averaging response measurements over a period of time to smooth the response measurements and remove noise from the response measurements.
  • Other approaches to reducing or removing noise from the response measurements can also be used.
  • decisions made using measurements may refer to decisions made using the raw measurements themselves or smoothed, processed, or cleaned measurement data.
  • the method may involve, in response to determining that the response measurement is below the desired lower limit of the response window or trending downwards, determining 308 new drilling parameter values that will increase the response measurement. The method may also involve comparing 310 the new drilling parameter values to sectional limits and comparing 312 the new drilling parameter value with hard limits.
  • the method may involve taking no additional action. In one embodiment, it may involve considering other drilling parameter values. In another embodiment, it may involve continuing to monitor the drilling parameters and response measurements. In one embodiment, it may involve changing the drilling parameter to the new value or providing a driller with an instruction to change the drilling parameter without making adjustments to the limits of the drilling parameter. In such an embodiment, the drilling operation may continue with the new drilling parameter while still acting within the sectional limits and the hard limits.
  • the drilling parameter value may be above the hard limit.
  • the method may involve searching for a different drilling parameter that may impact the response.
  • the method may involve increasing the upper value of the drilling parameter window to the new drilling parameter value, but only to the level of the hard limit.
  • a system may determine that a new RPM value ‘a’ will help mitigate a stick slip condition, where the sectional limit for RPM is ‘b’ and the hard limit is ‘c’ and a > c and a > b.
  • the system may increase the limit for the RPM above the sectional limit ‘b’ to the hard limit ‘c,’ not the larger RPM value ‘a.’
  • the drilling parameter value may be above the sectional limit and below the hard limit.
  • the method may involve, in such a case, increasing 316 the upper value of the drilling parameter window for the drilling parameter to the new drilling parameter value.
  • the method may involve automatically increasing the drilling parameter to the new drilling parameter value that will increase the response measurement.
  • an autonomous drilling system may increase the drilling parameter value.
  • the method involves increasing the upper value of the drilling parameter window and providing a notification to a driller of the change in the upper limit.
  • the method may also provide a recommendation to the driller to use the new drilling parameter value.
  • the method may also provide an explanation to the driller for the recommendation. For example, a system may provide a message to the driller indicating that the response measurement is outside the response window or trending downwards, and that using the new drilling parameter value may mitigate the downward trend or return the response measurement to the window.
  • the method may also involve monitoring the response measurement after increasing the drilling parameter to the new drilling parameter value.
  • the method may involve determining whether the response measurement is stabilizing within the response window and, in response, resetting the upper value of the drilling parameter window to the sectional limit for the drilling parameter.
  • the sectional limit may still be considered the preferred limit for the drilling parameters and the method may default back to the sectional limits once the response measurement returns to an acceptable range.
  • the method may involve gradually increasing the upper limit of the drilling parameter window to the new drilling parameter value. For example, it may be desirable to smoothly ramp up a drilling parameter over a period of time.
  • the method may generate transition values for the drilling parameter window that gradually transition the upper limit of the drilling parameter window to the new drilling parameter value.
  • the method may generate transition values for the drilling parameter window to gradually transition the drilling parameter window back to the sectional limit for the drilling parameter when the response measurement recovers and stabilizes within the response window.
  • the method may involve determining new drilling parameter values for multiple drilling parameters that, in combination, will increase the response measurement.
  • the method may involve comparing the drilling parameter values for one or more of this group of drilling parameters to their respective sectional limits and hard limits.
  • the approach may involve increasing the upper values for the drilling parameter windows with their respective drilling parameter values.
  • the system may give preference to those drilling parameter values that are above the sectional limits and below the hard limits.
  • the approach may look for a different parameter to adjust.
  • the method involves making the adjustments to all drilling parameter values that are associated with the response measurement while respecting the hard limits as described above.
  • the method involves minimizing the deviation from the sectional limits. For example, multiple drilling parameters may have an impact on a response measurement. In such an embodiment, new drilling parameter values may be determined for each of the drilling parameters that impact the response measurement. The system may determine the new drilling parameter values that will return the response measurement to the response window while minimizing the deviation from the sectional limit. For example, the method may involve applying a cost function to find the values of the drilling parameters that minimize the different between the new drilling parameter values and the sectional limits. Such an approach may facilitate the selection of new drilling parameter values that will return the response measurement to the response window while maintaining, to the extent possible, the benefits of adhering to or staying close to the sectional limits.
  • the method may also involve displaying via a computing system the drilling parameter window created using the new drilling parameter values.
  • the computing system may be part of a control system and allow the driller to adjust the drilling parameters within the drilling parameter window.
  • a control system in autonomous mode adjusts the drilling rig operation to execute the drilling operation within the drilling parameter window created using the new drilling parameter values.
  • Figure 4 illustrates one particular implementation of this approach to a particular response measurement.
  • Figure 4 is provided by way of illustration, and does not limit the applicability of the broader approach to different problems with different drilling parameters and different drilling responses.
  • the method involves measuring 402, in real time, the rate of penetration (ROP) during a directional drilling operation.
  • the method may also involve measuring 404, in real time, the differential pressure across a motor that is part of a bottom hole assembly (BHA) during the directional drilling operation.
  • the method may involve determining 406 whether the differential pressure is within a predefined differential pressure window that specifies the lower limit for the differential pressure and the upper limit for the differential pressure.
  • the method may involve determining 408 a new ROP value that will increase the differential pressure.
  • the method may also involve comparing 410 that new ROP value with the sectional limit for ROP and comparing 412 the new ROP value with the hard limit for ROP.
  • the method may involve determining 414 whether the new ROP is above the sectional limit and below the hard limit. In response to the new ROP value being above the sectional limit and below the hard limit, the method may involve increasing 416 the upper value of the ROP window to the new ROP value.
  • the method may involve setting the new ROP value to the hard limit and increasing the upper value of the ROP window to the hard limit. In one embodiment, if the new ROP value is equal to or below both the sectional limit and the hard limit, the method may involve increasing the ROP without changing the upper value of the ROP window.
  • the method involves automatically increasing the ROP to the new ROP value that will increase the differential pressure.
  • the method may also involve providing a notification to a driller of the increase in ROP along with an explanation for the increase.
  • the method may involve providing a driller with an instruction to increase the ROP and providing the driller with the updated ROP window.
  • the method may involve determining a minimum ROP that is different from the sectional limit and provide an updated lower bound for the ROP window as well.
  • the ROP window (or the drilling parameter more generally) may include only an upper bound.
  • an ROP window (or a drilling parameter window) includes such cases where only one of an upper bound and lower bound is provided.
  • the method involves monitoring the differential pressure after increasing the ROP to the new ROP value and determining whether the differential pressure is stabilizing within the predefined differential pressure window. In response to the differential pressure stabilizing, the method may involve resetting the upper value of the ROP window to the sectional limit for the ROP.
  • the method involves identifying new values for drilling parameters in addition to ROP that will increase the differential pressure and, for these additional drilling parameters, comparing the new values with the sectional limits and the hard limits for them. As described above in connection with ROP, the upper values of the windows for these additional drilling parameters may also be increased to respective new values for the additional drilling parameters.
  • Figure 5A illustrates one embodiment of a differential pressure and ROP relationship as described above.
  • Figures 5A and 5B illustrate example measurements displayed on a time and depth chart with time values (such as 18:37:30) and depth values (such as 12237) along the y axis.
  • the x axis illustrates sets of values shown along the time-depth values. From left to right, Figure 5A illustrates differential pressure measurements 502 and ROP measurements 504.
  • the far right illustrates ROP measurements 504.
  • this includes the ROP limit 522 shown as a solid black line.
  • the ROP limit 522 may be a maximum value only.
  • a lower ROP limit 522 may also be specified defining an ROP window.
  • the ROP limit 522 may vary.
  • the illustrated embodiment shows the original ROP 520 as the heavy dotted line.
  • the illustrated embodiment shows the driller following the ROP limit 522 closely.
  • proceeding with the drilling according to the ROP parameter specified by the original ROP 520 results in the original differential pressure 510 shown in the differential pressure measurements 502.
  • the original differential pressure 510 is frequently outside the differential pressure window specified by the differential pressure limits 512.
  • FIG. 5B illustrates the same example, but with the addition of dynamic adjustment of the ROP drilling parameter as described herein.
  • the trigger 505 represents one approach to determining whether the response measurement is within a response window or trending downwards. As shown in Figure 5B, the trigger 505 may a value between, for example, -0.1 and 1.1. In the illustrated embodiment, the trigger 505 causes the adjustments to the ROP value when it is high and causes the system to revert to the sectional limits when it is low.
  • Figure 5B illustrates the response of the trigger 505 to measurements of the new differential pressure 514.
  • Differential pressure limits 512 represent the response window for the differential pressure in this example.
  • the differential pressure limits 512 represent the lower and upper boundaries for the differential pressure within a particular section. While the illustrated embodiment shows the differential pressure limits 152 as static values, the differential pressure limits 512 may vary in different wells, or different sections of the same well.
  • the trigger 505 When the new differential pressure 514 is steadily below the differential pressure limits 512, or decreasing towards the lower limit of the differential pressure limits 512, the trigger 505 has a high value triggering adjustments to the ROP value and ROP limit 522. When the new differential pressure 514 measurements are stable or trending upwards, the system may deactivate the trigger 505 and the ROP limit 522 and recommended ROP parameter revert to the sectional limit. The sensitivity of the trigger 505 to changes may be tuned to reduce the likelihood of the trigger 505 being activated in response to noise or fluctuations at or near the differential pressure limits 512.
  • the ROP measurements 504 show the new ROP 524 values and the original ROP limit 522. In comparison to the embodiment shown in Figure 5A, the new ROP 524 values do not adhere as closely to the ROP limit 522. However, Figure 5B illustrates how the dynamic adjustment of the ROP limit 522 results in a new differential pressure 514 value that is within the window defined by the differential pressure limits 512 more than the case shown in Figure 5 A.
  • the driller or system frequently changes the new ROP 524 in the section to control the new differential pressure 514.
  • the system may relax the ROP limit 522. In one embodiment, the system relaxes the ROP limit 522 by fifty feet per hour.
  • the new ROP limit is not shown in Figure 5B for clarity; however, in the illustrated embodiment, the new ROP limit is dynamically increasing to a level that is above the sectional limit for the ROP (represented by the ROP limit 522) but below the hard limits for the ROP, above which operating the ROP would result in risks to safety, equipment, or the well.
  • This approach strikes a balance between protecting safety and equipment (by adhering to hard limits), using the expertise of the team (by using sectional limits by default), while still maintaining the flexibility to respond appropriately to events (such as the differential pressure 514 falling outside of the differential pressure limits 514) to provide a result that more consistently provides response measurements that are within specified windows.
  • the approach described herein may be implemented as a set of instructions to be saved in memory and executed by a processor.
  • the computer system may be part of a drilling system.
  • the computer system may be part of a drilling system as illustrated in Figure 2.
  • the drilling system may include a rig control system that communicates with the rig equipment.
  • the computer system may be part of the rig control system.
  • the computer system may be separate from the rig control system and communicate with the rig control system using a software interface.
  • the computer system may receive, in real time, drilling parameter measurements and response measurements during the drilling operation.
  • the computer system may determine whether the response measurements are within the response window that defines the desired lower limit and the desired upper limit for the response measurements.
  • the computer system may determine a new drilling parameter value that will increase the response measurement.
  • the computer system may compare the new drilling parameter value with sectional limits and hard limits for the drilling parameter value. If the drilling parameter value is above the sectional limit and below the hard limit, the computer system may increase the upper value of the drilling parameter window to the new drilling parameter. The computer system may also increase the drilling parameter itself (or instruct a driller to do so) to a value that is equal to or below the updated upper value. This approach may be used to dynamically adjust both the drilling parameter values that define the window of acceptable values for the drilling parameter and to also update the drilling parameter itself.
  • the methods of the present disclosure may be executed by a computing system.
  • Figure 6 illustrates an example of such a computing system 600, in accordance with some embodiments.
  • the computing system 600 may include a computer or computer system 601A, which may be an individual computer system 601A or an arrangement of distributed computer systems.
  • the computer system 601A includes one or more analysis modules 602 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module 602 executes independently, or in coordination with, one or more processors 604, which is (or are) connected to one or more storage media 606.
  • the processor(s) 604 is (or are) also connected to a network interface 607 to allow the computer system 601 A to communicate over a data network 609 with one or more additional computer systems and/or computing systems, such as 60 IB, 601C, and/or 60 ID (note that computer systems 60 IB, 601C and/or 60 ID may or may not share the same architecture as computer system 601 A, and may be located in different physical locations, e.g., computer systems 601 A and 601B may be located in a processing facility, while in communication with one or more computer systems such as 601 C and/or 60 ID that are located in one or more data centers, and/or located in varying countries on different continents).
  • additional computer systems and/or computing systems such as 60 IB, 601C, and/or 60 ID
  • computer systems 60 IB, 601C and/or 60 ID may or may not share the same architecture as computer system 601 A, and may be located in different physical locations, e.g., computer systems 601 A and 601B may
  • a processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.
  • the storage media 606 may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of Figure 6 storage media 606 is depicted as within computer system 601 A, in some embodiments, storage media 606 may be distributed within and/or across multiple internal and/or external enclosures of computing system 601 A and/or additional computing systems.
  • Storage media 606 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLURAY® disks, or other types of optical storage, or other types of storage devices.
  • semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories
  • magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape
  • optical media such as compact disks (CDs) or digital video disks (DVDs)
  • DVDs digital video disks
  • Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture).
  • An article or article of manufacture may refer to any manufactured single component or multiple components.
  • the storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.
  • computing system 600 contains one or more drilling control module(s) 608.
  • computer system 601 A includes the drilling control module 608.
  • a single drilling control module may be used to perform some aspects of one or more embodiments of the methods disclosed herein.
  • a plurality of drilling control modules may be used to perform some aspects of methods herein.
  • computing system 600 is merely one example of a computing system, and that computing system 600 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of Figure 6, and/or computing system 600 may have a different configuration or arrangement of the components depicted in Figure 6.
  • the various components shown in Figure 6 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.
  • the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are included within the scope of the present disclosure.
  • Computational interpretations, models, and/or other interpretation aids may be refined in an iterative fashion; this concept is applicable to the methods discussed herein. This may include use of feedback loops executed on an algorithmic basis, such as at a computing device (e.g., computing system 600, Figure 6), and/or through manual control by a user who may make determinations regarding whether a given step, action, template, model, or set of curves has become sufficiently accurate for the evaluation of the subsurface three-dimensional geologic formation under consideration.
  • a computing device e.g., computing system 600, Figure 6

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Abstract

L'invention concerne des procédés, des systèmes informatiques et des supports lisibles par ordinateur permettant de régler dynamiquement des paramètres de forage pendant une opération de forage. L'approche consiste à recevoir, en temps réel, des mesures de paramètres de forage et des mesures de réponse pendant une opération de forage. Si les mesures de réponse sont inférieures à la limite inférieure d'une fenêtre ou tombent vers le bas, l'approche détermine une nouvelle valeur de paramètre de forage qui augmentera la mesure de réponse. L'approche règle dynamiquement la valeur de paramètre de forage au-dessus de la limite sectionnelle, tout en respectant des limites dures. Lorsque la valeur mesurée s'améliore, l'approche renvoie la limite du paramètre de forage à la limite sectionnelle.
EP21908051.2A 2020-12-17 2021-12-17 Réglages dynamiques de limites de paramètres de forage Pending EP4264012A1 (fr)

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US202063199272P 2020-12-17 2020-12-17
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US7100708B2 (en) * 2003-12-23 2006-09-05 Varco I/P, Inc. Autodriller bit protection system and method
WO2012080810A2 (fr) * 2010-12-13 2012-06-21 Schlumberger Technology B.V. Mesure de vitesse de rotation d'un moteur en fond de trou
AU2013327663B2 (en) * 2012-10-03 2016-03-10 Shell Internationale Research Maatschappij B.V. Optimizing performance of a drilling assembly
US9593566B2 (en) * 2013-10-23 2017-03-14 Baker Hughes Incorporated Semi-autonomous drilling control
US10591625B2 (en) * 2016-05-13 2020-03-17 Pason Systems Corp. Method, system, and medium for controlling rate of penetration of a drill bit

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