WO2021170765A1 - Determination of drillstring parameters and associated control - Google Patents
Determination of drillstring parameters and associated control Download PDFInfo
- Publication number
- WO2021170765A1 WO2021170765A1 PCT/EP2021/054766 EP2021054766W WO2021170765A1 WO 2021170765 A1 WO2021170765 A1 WO 2021170765A1 EP 2021054766 W EP2021054766 W EP 2021054766W WO 2021170765 A1 WO2021170765 A1 WO 2021170765A1
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- WIPO (PCT)
- Prior art keywords
- drillstring
- model
- wellbore
- bit
- torque
- Prior art date
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B37/00—Methods or apparatus for cleaning boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/04—Measuring depth or liquid level
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- the present invention relates to a method for modelling drillstrings in use, and in particular, though not exclusively, to an applied method for operating or determining properties of the drillstring using the model.
- Directional drilling can provide significant benefits, such as improved access to distant formations and penetrating reservoirs horizontally, amongst others.
- the costs of directional-well drilling are often high. There are a number of factors in this, including substantial non-productive time, which can be in the order of 30 percent of the drilling time.
- techniques that can reduce downtime, improve utilisation and improve drilling efficiency can make a highly significant difference to drilling operations.
- Finite element models can be used to model the drillstring, e.g. to determine properties of the drillstring, to predict its behaviour and/or to determine the values of operating parameters of the drillstring required to achieve a desired operation.
- These finite element models can beneficially take into account complex geometries.
- such models are generally computationally intensive, slow to implement and difficult to implement in real time. As such, finite element models may have limited use, particularly in real time operational situations.
- a method for modelling a drillstring e.g. for dynamically modelling the drillstring in a wellbore.
- the method may comprise providing a model of the drillstring.
- the model may be or comprise a multi-dimensional lumped-element model.
- the model may be a three dimensional model.
- the model may represent the drillstring by a sequence of alternating springs and elements.
- Each element may describe the mass and/or the moment of inertia of a corresponding part of the drillstring.
- Each spring may represent at least one of: axial, torsional and/or bending stiffnesses of a corresponding part of the drillstring.
- the model may describe one or more forces on a plurality of the elements, e.g. on each element, by one or more equations, which may comprise a linear part that comprises constant coefficients and/or may comprise a non-linear part that includes one or more of: one or more non-linear terms, one or more non-smooth terms, one or more time dependent terms and/or one or more coupled terms.
- the method may comprise recalculating the model for a plurality of time steps.
- Recalculating the model for the respective time step may comprise calculating positions, orientations and/or associated derivatives thereof of at least some or all of the elements for the respective time step based on positions, orientations and/or associated derivatives thereof of at least some or all of the elements at a previous time step, e.g. by describing the non-linear part by a form of expansion with respect to time and solving the one or more equations analytically or by the use of exponential integrators for the duration of the respective time step.
- the expansion may be or comprise a Taylor series expansion.
- the expansion may comprise, for example, Laurent series expansion, fourier series expansion, applying Pade’s approximation, or other polynomial approximation.
- the method may comprise recalculating the model at a recalculating rate e.g. each time step, which may in the order of 1 to 1000000 milliseconds, but is not limited to this.
- the positions, orientations and/or associated derivatives of the elements may be in one, two or three dimensions.
- the recalculating of the model for the respective time steps may comprise analytically solving the model, or solving the model by the use of exponential integrators, for each time step.
- the recalculating of the model for the respective time steps may comprise analytically solving the one or more equations for the duration of the time step in order to determine a change in the positions, orientations and/or associated derivatives of at least some or all of the elements relative to the previous time step.
- the method may comprise not recalculating the constant coefficients of the linear term for every time step, e.g. for only some and less than all of the time steps.
- the method may comprise recalculating the constant coefficients according to a recalculation condition.
- the one or more equations may use or comprise the mass and/or the moment of inertia represented by at least one or each segment and/or the torsional and/or bending stiffnesses represented by at least one or each spring.
- the method may comprise receiving data.
- the data may be received from a database.
- the data may be data from one or more measurement devices that measure properties of the drillstring, the wellbore in which the drillstring is located, the drilling system that the drillstring is being used with, the operation of the drillstring, the environment around the drillstring and/or the like.
- the data may be real time data received during use of the drillstring and relating to the drillstring in use and/or to the use of the drillstring.
- the data may comprise time stamped data and/or the data may comprise static data.
- the one or more equations may use or comprise the data or parameters of the drillstring derived from the data, which may be in addition to the mass and/or the moment of inertia represented by at least on or each segment and/or the torsional and/or bending stiffnesses represented by at least one or each spring.
- the linear part may describe side forces on the drill string and/or parameters of or forces on the drillstring that remain constant between time steps.
- the recalculating of the model may comprise dynamically or repeatedly modifying the model according to a predefined set of rules or detection algorithms.
- the predefined set of rules or detection algorithms may comprise a change in one or more of: drillstring length or dimensions, detected activity code, expected friction forces, and/or expected intrinsic energy of the rock, but is not limited to these.
- the predefined set of rules or detection algorithms may adjust data output as well as parameters of the model.
- model described herein requires much less computational resources, and can be processed much more quickly, than equivalent finite element models, thereby allowing for dynamic, real time use.
- mathematical stiffness and non-linear/non-smooth effects that could otherwise have a significant detrimental effect on the accuracy of the model may be reduced and/or prevent use of this type of model, can be eliminated or at least rendered insignificant.
- the model may comprise axial movement functionality for determining properties associated with axial movements of the drill string.
- the model may comprise torsional movement functionality for determining properties associated with torsional movements of the drill string.
- the model may comprise lateral movement functionality for determining properties associated with lateral movements of the drill string.
- the model may describe at least coupled axial and torsional movements of the drillstring and optionally also coupled lateral movements of the drillstring.
- the model may represent coupling between the effects of axial and torsional movements of the drillstring and optionally lateral movements.
- the axial movement functionality may comprise modelling the axial movements of the drill string using the mass of one or more or each of the elements and the spring constant related to axial compression and expansion of one or more or each of the elements.
- the method may comprise determining a weight on bit and/or torque on bit using the model.
- the model may comprise a bit rock model that describes the interaction between the drill bit of the drillstring and the rock currently being drilled.
- the model for the drillstring may take into account: the bit rock interaction model and/or coupled axial and torsional dynamics for vertical and/or deviated wellbores.
- the method may comprise determining one or more of: a rate of penetration of the bit, the weight on bit, the torque on bit and/or the hole depth using the model, e.g. using the bit rock model, which may be in addition to the modelling of the coupled axial and torsional movements of the drillstring and may be for one or both of vertical and/or deviated wellbores.
- the method may comprise discounting effects due to axial vibrations in the bit rock model.
- the method may comprise determining the interaction between the drill bit and the rock currently being drilled using the bit rock model based on an intrinsic specific energy associated with the rock currently being drilled.
- the method may comprise determining measurements of one or more of the weight on bit, the torque on bit, the rate of penetration of the bit and/or the hole depth, e.g. based on surface and/or downhole measurements.
- the method may comprise determining or updating the intrinsic specific energy by minimizing the difference between the values of one or more of the weight on bit, the torque on bit, the rate of penetration of the bit and/or the hole depth determined from the surface and/or downhole measurements and those determined using the bit rock model.
- the model may comprise a friction model component for determining wall friction forces between the drillstring and the wall of the wellbore.
- the method may comprise using the model, e.g. the friction model component, to determine wall friction forces between the drillstring and the wall of the wellbore.
- the friction model may be a dynamically calculated model.
- the friction model may take into account coupled axial and torsional movements or dynamics of the drillstring, e.g. for one or both of vertical and/or deviated wellbores.
- the friction model may be calculated based on surface and/or downhole measurements.
- the model may comprise a friction model component for determining wall friction forces between the drillstring and the wall of the wellbore based on friction coefficients.
- the method may comprise determining or updating the friction coefficients by minimizing the difference between the output of the model, e.g. of the friction model, and measurements taken at the surface or downhole, e.g. using sensors or operating parameters of the drillstring handling system.
- the features described above allow the model to account for both axial and rotational or torsional movements and optionally lateral movements of the drillstring. These movements may be coupled and the described method may account for coupling between these movements, which leads to a more accurate model.
- the model may comprise a buoyancy factor. Each element may be associated with a buoyancy factor, which may be representative of the associated element. The buoyancy factor for a given element may represent a buoyancy effect on the part of the drillstring that is represented by the element.
- the model may comprise a friction model component that determines a factor for friction forces on the drillstring due to material in the wellbore.
- the material in the wellbore may comprise, for example, one or more of: drill mud, oil, water, drilling fluid, cement, spacers, completion fluids, formation fluids, and the like, but is not limited to this.
- the method may comprise adding mass to a bottom or lowermost element (e.g. weight) of the model to account for forces acting on the drillstring from the fluid, e.g. according to a suitable equation, correction factor or the like.
- the method may comprise adding a factor accounting for viscous forces from the fluid on the drillstring and/or for flow speed of the fluid.
- the model may comprise a normal force model.
- the normal force model may model normal forces acting on each of the elements or segments.
- the normal force model may be configured to output wall friction forces, such as but not limited to Coulomb friction, Stribeck friction, Karnoop friction and sticktion models e.g. the friction force between two sliding surfaces, wherein one of the sliding surfaces is an outer surface of the drillstring.
- the Coulomb friction may be a friction between an inner wall of the wellbore and the outer surface of the drillstring.
- the method may comprise determining whether the drillstring is in a wellbore casing or not, or whether specific segments or weights represent sections of the drillstring are within a wellbore casing or not, e.g. based on predetermined wellbore construction data and/or the determined location of the drillstring and/or segments.
- the method may comprise adjusting the normal force model depending on the determination of whether or not the drillstring or the weights or segments of the drillstring are within the casing.
- Friction forces due to the well fluid and/or wall friction may have significant impact of the drillstring and the described method appreciates the significance of these factors and may account for them, improving the accuracy of the model.
- the method may comprise determining forces acting on a bottom hole assembly and/or drillbit connected to the drillstring.
- the bottom hole assembly and/or drillbit may be represented by a lowermost or bottom segment or weight. Certain effects and parameters of the drillstring may be significantly influenced by the downhole mass being supported by it, e.g. the bottom hole assembly and the drill bit.
- the method may comprise using the model to determine hookload of a drilling system that comprises the drillstring, in use.
- the method may comprise using the model to determine torque of the drillstring, in use.
- the method may comprise displaying plots of the hookload and/or torque determined from the model.
- the hookload and torque may allow determination of a variety of other parameters and as such may be important variables in the operation of drilling operations.
- the automatic determination of hookload and/or torque as described herein may minimise issues due to incomplete or deficient manually collected or derived data.
- the method may comprise using the model to determine whether the drillstring, e.g. a given segment, lies on an upper or high side of the interior of the wellbore or on a lower or bottom side of the interior of the wellbore, e.g. to determine whether the segment is in the top half or bottom half of the part of the wellbore in which the segment is located.
- the method may comprise determining whether the drillstring, e.g. a given segment or segments, lies on an upper or high side of the interior of the wellbore or on a lower or bottom side of the interior of the wellbore based on the sign of the normal forces and/or accelerations on the drillstring or section(s) of the drillstring.
- the determination of whether one or more or each sections of the drillstring are located in an upper or lower part of an axial cross section of the part of the wellbore in which the respective segment is located can be beneficial in better controlling or selecting a cleaning operation for cleaning the wellbore.
- the method may comprise using the model to determine which segments of the drillstring are moving and/or which are stalled, e.g. due to friction.
- the method may comprise using the model to determine which segments of the drillstring are moving and/or which are stalled based on the values of axial position, rate of change of axial position or speed of the drillstring or segment of the model, and/or the rotary speed associated with the drillstring or segment of the model, e.g. whether the rate of change of axial position and/or rotary speed are equal to zero or less than a threshold.
- the method may comprise displaying data from the model in a graphical user interface, e.g. in a graphical user interface of a drilling system controller or operations system for operating drilling operations that comprise the drillstring.
- the method may comprise determining an alarm or alert condition.
- the alarm or alert condition may be representative of one or more of: overpulls (increased hookload while pulling out), tookweights (reduced hookload while running in), maxed out top drive torque, top drive stallouts and/or erratic torque.
- the method may comprise determining whether the alarm or alert condition has been met from the output of the model and raising an alert or alarm based on the determination that the alarm or alert condition has been met.
- the method may comprise automatically controlling a drilling operation and/or a issuing a control command to control a drilling operation.
- the method may comprise using the model to control how activities using the drillstring are executed, such as one or more of, but not limited to; starting and stopping rotation, starting and stopping tripping in, starting and stopping tripping out, starting and stopping reaming in, starting and stopping reaming out and starting and stopping to drill.
- the method may comprise controlling motion of a drillstring, e.g. raising or lowering a drillstring and/or varying rotation of the drillstring, based on one or more outputs of the model, e.g. based on at least the determination of whether the drillstring, e.g.
- a given segment lies on an upper or high side of the interior of the wellbore or on a lower or bottom side of the interior of the wellbore and/or one or more of: the hookload, torque, the determination of which segments of the drillstring are moving and/or which are stalled, the values of axial position, rate of change of axial position or speed of the drillstring or segment of the model, and/or the rotary speed associated with the drillstring or segment of the model, e.g. whether the rate of change of axial position and/or rotary speed are equal to zero or less than a threshold.
- the method may comprise controlling a cleaning operation for cleaning the wellbore using the drillstring based on the one or more outputs of the model.
- the model can be used to compensate for heave motions and more effectively control tripping and reaming operations, i.e keeping steady tripping or reaming speeds,
- the method may comprise determining, e.g. automatically detecting, when a section of the drillstring is added or a section of the drillstring is removed.
- the method may comprise receiving or calculating one or more hoist or block positions and/or bit depths, e.g. from one or more sensors, controller settings and/or by using the model.
- the determining, e.g. automatically detecting may comprise detecting when a new section of the drillstring is added or an existing section of the drillstring is removed based on at least the one or more hoist or block positions and/or bit depths.
- the method may comprise determining a new drillstring length accounting for the addition or removal of the section of the drillstring.
- the method may comprise updating, e.g. automatically updating, the model with the new drill string length.
- the method may comprise storing states of the model for a plurality of times, also called “snapshots”, e.g. in a database.
- the states may comprise historic information that the model requires to restart for a certain time instance.
- the method may comprise providing a snapshot of the drillstring for any given time instance by recalling the state associated with the given time instance and recalculating the model based on the recalled state. This may mean that the model can restart at any time/date snapshot that is stored as a state. This arrangement may effectively provide rollback functionality that involves starting at a prior time step.
- the method may comprise providing a functionality to restart calculation of the drillstring form any of these stored snapshots.
- the method may comprise determining one or more parameters of the wellbore, such as but not limited to, one or more of: intrinsic specific energy, downhole friction factors, weight on bit, torque on bit, rate of penetration and/or an on-bottom determination using the rollback functionality and/or by providing the snapshots of the drillstring.
- the method may comprise trying different parameters or parameter curves (e.g. intrinsic specific energy curves or downhole friction factor curves) and determining a difference between a measured or calculated property and the corresponding values of the property determined based on the respective parameter or parameter curve, which may be over fixed time spans.
- the measured or calculated property may be, comprise, be representative of or depend on the surface weight on bit (SWOB) and the determined property may be, comprise, be representative of or depend on a calculated surface weight on bit (SWOB CALC).
- SWOB CALC surface weight on bit
- the measured or calculated property may be, comprise, be representative of or depend on the hookload (HKL) and the determined property may be, comprise, be representative of or depend on a calculated hookload (HKL CALC).
- the method may comprise determining when the difference between the measured or calculated property and the corresponding values of the property determined based on the respective parameter curve exceeds a threshold.
- the method may comprise rolling back, e.g.
- the method may comprise repeating the process based on the adjusted or changed parameter curve.
- the model may be used to store wear characteristics of every joint of the drillstring. For instance, but not limited to, the information about the stress as a function of time may be used to determine fatigue life, e.g. using Palmgren-Miner’s rule.
- the model can also be used as input to wear models when a hard surface is sliding along a softer surface (see for instance “Mechanical wear models for metallic surfaces in sliding contact by B. S: Hochenhull, E. M. Kopalinsky and P. L. B. Oxley in Journal of Physics D: Applied Physics 25, 1992, A266-A272”). This relates to wear on the drillstring, the casing and also the open hole itself, for instance in determining key-seatings and out of gauge holes. These may beneficially be used for maintenance purposes.
- the method may comprise using the values and parameters of the drillstring determined using the model to detect obviously erroneous measurements, e.g. of one or more of, but not limited to; hookload, weight on bit, rate of penetration, block height, bit depth, hole depth, rotary speed, torque, downhole weight on bit, downhole rotation speed, downhole torque, flow speed, stand pipe pressure and ECD, for example, by comparing the determines values or parameters with a set, pre-set or determined threshold range and determining that the measurements are erroneous if they lie outwith the threshold range.
- the method may comprise using the model to detect resonant frequencies while drilling under various combinations of one or more of the following, but not limited to: rotary speed, weight on bit and rate of penetration, estimated intrinsic specific energy.
- the method may comprise converting the system of equations for the second order differential equations to a larger system of first order differential equations that are solved by exponential integrators.
- a second aspect of the present disclosure is a method for cleaning a wellbore using a drillstring located within the wellbore, the method comprising selectively inducing lateral motions of the drillstring in the wellbore, such as motions of the drillstring in a direction between an upper and lower part of the wellbore.
- the method may comprise selectively inducing lateral motions in the drillstring in the wellbore responsive to one or more outputs of a model, such as a model as described above in relation to the first aspect of the present disclosure.
- the model may model one or more segments of the drillstring. Each segment may be represented by an element and spring. A plurality of segments of the drillstring may be represented in the model by a plurality of elements sequentially connected by springs.
- the model may represent the drillstring by a sequence of alternating springs and elements.
- Each element may describe the mass and/or the moment of inertia of a corresponding part of the drillstring.
- Each spring may represent at least one of: axial, torsional and/or bending stiffnesses of a corresponding part of the drillstring.
- the model may describe one or more forces on a plurality of the elements, e.g. on each element, by one or more equations, which may comprise a linear part that comprises constant coefficients and/or may comprise a non-linear part that includes one or more of: one or more non-linear terms, one or more non-smooth terms, one or more time dependent terms and/or one or more coupled terms.
- the method may comprise recalculating the model for a plurality of time steps.
- Recalculating the model for the respective time step may comprise calculating positions, orientations and/or associated derivatives thereof of at least some or all of the elements for the respective time step based on positions, orientations and/or associated derivatives thereof of at least some or all of the elements at a previous time step, e.g. by describing the non-linear part by a form of expansion with respect to time and solving the one or more equations analytically or by the use of exponential integrators for the duration of the respective time step.
- the expansion may be or comprise a Taylor series expansion.
- the expansion may comprise, for example, Laurent series expansion, fourier series expansion, applying Pade’s approximation, or other polynomial approximation.
- the recalculating of the model for the plurality of time steps may comprise dynamically and/or repeatedly switching between models or sub-models and/or recalculating the model for each time step.
- the method may comprise periodically switching between models or sub-models and/or recalculating the model, e.g. according to a set, selected or predefined switching or recalculation rate.
- the predefined switching or recalculation rate e.g. each time step, may in the order of 1 to 1000000 milliseconds, but is not limited to this.
- the recalculating of the model for the respective time steps may comprise analytically solving the model, or solving the model by the use of exponential integrators, for each time step.
- the outputs of the model may comprise one of more of: axial positions of segments of the drillstring, rotary speeds of segments of the drillstring, hookload of a drilling system that comprises the drillstring, torque of the drillstring, downhole tension forces on the drillstring, surface and/or downhole torques on the drillstring, normal forces and/or friction forces on the drillstring, a determination of whether the drillstring or segments of the drillstring lie on an upper or high side of the interior of the wellbore or on a lower or bottom side of the interior of the wellbore, a determination of which segments of the drillstring are moving and/or which are stalled, an angle or orientation of the segment of the drillstring and/or a bottom hole assembly or drill bit, and/or the like.
- the method may comprise selectively inducing lateral motions in the drillstring in the wellbore responsive to one or more of: flow speed in the wellbore, geometry of the wellbore, rheology of mud and/or other wellbore fluid in the wellbore, cutting size, roughness of the wellbore, and/or the like, which may be measured, estimated or output from the model.
- the selectively inducing lateral motions in the drillstring may comprise manipulating the block height, e.g. by repeatedly and/or rapidly raising and lowering the block height.
- the method may comprise selectively inducing lateral motions in those segments of the drillstring that are located in a lower half of the wellbore in a vertical cross sectional view through the respective segment of the wellbore and are not rotating and/or in those segments of the drillstring that are located in an upper half of the wellbore in the vertical cross sectional view through respective segment of the wellbore, e.g. regardless of whether they are rotating or not.
- the method may comprise cleaning the wellbore by inducing, or selectively inducing, lateral motions in the drillstring in wellbores or sections of the wellbore that are obliquely oriented with respect to vertical, which may be oriented within a threshold range of angles, e.g. at over 20° to vertical such as 30° to vertical and over, such as between 20° and 90° to vertical, e.g. from 30° to 65° from vertical.
- the method may comprise operating a drillstring handling system, which may comprise a hoist for hoisting the drillstring to induce the lateral motions in the drillstring in the wellbore.
- the method may comprise rotating the drillstring, e.g. using the drillstring handling system, whilst inducing the lateral motions and/or inducing the lateral motions whilst the drillstring is not rotating.
- the method may comprise lifting and lowering or releasing the drillstring, e.g. using the hoisting system.
- the induced lateral motions in the drillstring in the wellbore may comprise moving the drillstring between the upper portion of the wellbore and the lower portion of the wellbore.
- the lower portion of the wellbore may be provided or correspond to a bed of cuttings or other material to be removed.
- the induced lateral motions in the drillstring in the wellbore may comprise moving the drillstring between a configuration in which the drillstring is located outwith or free from the bed of cuttings or other material to be removed and a configuration in which the drillstring is located or embedded in the bed of cuttings or other material to be removed.
- the induced lateral motions in the drillstring in the wellbore may comprise making motions, such as small motions, in the drillstring in which the bottom hole assembly attached to the drillstring is either static or moves less than a threshold amount.
- the induced lateral motions in the drillstring in the wellbore may comprise making plurality of pulls, such as rapid pulls, on the drillstring in which the bottom hole assembly moves, e.g. by greater than the threshold amount, and optionally in which the motions may be made without rotating the drillstring.
- the induced lateral motions in the drillstring in the wellbore may comprise inducing harmonic axial movements in the drillstring, e.g. periodic movements that are at a harmonic or resonant frequency of the drillstring, which may optionally be carried out whilst rotating the drillstring.
- the method may comprise selecting how or where to selectively apply the induced lateral motions, e.g. to which segment or segments of the drillstring, depending on the output from the model. For example, for segments in which the drillstring is determined using the model to be on a lower or bottom side of the interior of the wellbore and/or when an associated segment of the drillstring is determined to have stalled, then an operation of rotating the drillstring may be selected, and optionally no lateral motions are applied. In another example, for segments in which the drillstring is determined using the model to be on an upper or upmost side of the interior of the wellbore, then lateral motions may be selectively applied.
- the method may comprise selecting how to apply the lateral motions, e.g. to select from any of the above, depending on the output from the model, e.g. depending on the output of the model.
- the method may comprise selecting how to apply the lateral motions, e.g. whilst the drillstring is rotating or not rotating and/or whether to move the down hole assembly less than the threshold amount or more than the threshold and/or to determine a repetition rate or speed of raising and lowering of the drillstring, dependent on the output from the model.
- a third aspect of the present disclosure is a system comprising at least one processing device and a computer readable data store storing a computer program, the computer program comprising instructions that, when the program is implemented by the at least one processor, cause the processor to carry out the method of the first aspect.
- a controller for controlling a drillstring handling system, the drillstring handling system comprising a hoist for hoisting the drillstring and a rotation mechanism for rotating the drillstring, the controller comprising at least one processor and a computer readable data store storing a computer program, the computer program comprising instructions that, when the program is implemented by the at least one processor, cause the processor to carry out the method of the second aspect to control the drillstring handling system, e.g. to induce lateral motions in the drillstring and/or in selected segments of the drillstring, which may be based on one or more outputs of the model.
- a fifth aspect of the present disclosure is a computer program product comprising instructions that, when the program is implemented by the at least one processor, cause a processor or controller for a drillstring handling system to carry out the method of the first aspect or the method of the second aspect.
- the computer program product may be embodied on a physical, non-transient computer readable medium.
- a drillstring handling system comprising the controller of the fourth aspect, a hoist for hoisting the drillstring and a rotation mechanism for rotating the drillstring, wherein the hoist and/or the rotation are selectively controllable by the controller.
- a seventh aspect of the present disclosure is a method for determining parameters of a drillstring in a wellbore, the method comprising providing a model of the drillstring.
- the drillstring may be suspending on a hoist or on a block.
- the drillstring may comprise a drillbit.
- the method may comprise automatically detecting when a section of the drillstring is added or removed.
- the method may comprise receiving or calculating one or more hoist or block positions and/or bit depths, e.g. from one or more sensors, controller settings and/or by using the model.
- the automatically detecting may comprise detecting when a new section of the drillstring is added or an existing section of the drillstring is removed based on at least the one or more hoist or block positions and/or bit depths.
- the method may comprise determining a new drillstring length accounting for the addition or removal of the section of the drillstring.
- the method may comprise updating, e.g. automatically updating, the model with the new drill string length.
- the model may comprise any feature relating to a model described above in relation to any previous aspect, particularly the first aspect.
- an eighth aspect of the present disclosure is a method for determining parameters of a drillstring in a wellbore, the method comprising providing a model of the drillstring.
- the method may comprise determining one or more of: a weight on bit, a torque on bit, a rate of penetration of the bit, a hole depth of the wellbore and/or axial and torsional vibrations, using the model.
- the model may comprise any feature relating to a model described above in relation to any previous aspect, particularly the first aspect.
- the model may comprise a bit rock model that describes the interaction between the drill bit of the drillstring and the rock currently being drilled.
- the model for the drillstring may take into account: the bit rock interaction model and/or coupled axial and torsional dynamics for vertical and/or deviated wellbores.
- the method may comprise determining one or more of: a rate of penetration of the bit, the weight on bit, the torque on bit and/or the hole depth using the model, e.g. using the bit rock model, which may be in addition to the modelling of the coupled axial and torsional movements of the drillstring and may be for one or both of vertical and/or deviated wellbores.
- the method may comprise discounting effects due to axial vibrations in the bit rock model.
- the method may comprise determining the interaction between the drill bit and the rock currently being drilled using the bit rock model based on an intrinsic specific energy associated with the rock currently being drilled.
- the method may comprise determining measurements of one or more of the weight on bit, the torque on bit, the rate of penetration of the bit and/or the hole depth, e.g. based on surface and/or downhole measurements.
- the method may comprise determining or updating the intrinsic specific energy by minimizing the difference between the values of one or more of the weight on bit, the torque on bit, the rate of penetration of the bit and/or the hole depth determined from the surface and/or downhole measurements and those determined using the bit rock model.
- a ninth aspect of the present disclosure is a method for determining parameters of a drillstring in a wellbore, the method comprising providing a model of the drillstring.
- the model may comprise any feature relating to a model described above in relation to any previous aspect, particularly the first aspect.
- the model may comprise a friction model component for determining wall friction forces between the drillstring and the wall of the wellbore.
- the method may comprise using the model, e.g. the friction model component, to determine wall friction forces between the drillstring and the wall of the wellbore.
- the friction model may be a dynamically calculated model.
- the friction model may take into account coupled axial and torsional movements or dynamics of the drillstring, e.g. for one or both of vertical and/or deviated wellbores.
- the friction model may be calculated based on surface and/or downhole measurements.
- the model may comprise a friction model component for determining wall friction forces between the drillstring and the wall of the wellbore based on friction coefficients.
- the method may comprise determining or updating the friction coefficients by minimizing the difference between the output of the model, e.g. of the friction model, and measurements taken at the surface or downhole, e.g. using sensors or operating parameters of the drillstring handling system.
- a method for determining properties of a drillstring in a wellbore comprising providing a model of the drillstring.
- the model may comprise any feature relating to a model described above in relation to any previous aspect, particularly the first aspect.
- the method may comprise storing states of the model for a plurality of times, e.g. in a database.
- the states may comprise historic information that module requires to restart for a certain time instance.
- the method may comprise providing a snapshot of the drillstring for any given time instance by recalling the state associated with the given time instance and recalculating the model based on the recalled state. This may mean that the model can restart at any time/date snapshot that is stored as a state. This arrangement may effectively provide rollback functionality that involves starting at a prior time step.
- the present invention is intended to cover apparatus configured to perform any feature described herein in relation to a method and/or a method of using or producing, using, repairing or manufacturing any apparatus feature described herein.
- Figure 1 is a schematic illustrating a deviated wellbore and associated drilling apparatus
- Figure 2 is a flowchart showing the operation of a modelling process for determining and providing parameters of a drillstring of the drilling apparatus shown in Figure 1 ;
- Figure 3 is a schematic representation of a multi-dimensional lumped element model used in the process of Figure 2 showing some parameters of the model relating to axial forces on each element;
- Figure 4 is a schematic representation of the multi-dimensional lumped element model of Figure 3 showing some parameters of the model relating to torques on each element.
- Figure 5 shows a GUI displaying parameters of the drillstring determined using the process of Figure 2;
- Figure 6 shows a GUI view displaying a torque and drag plot determined using the process of Figure 2;
- Figure 7 shows a GUI displaying further parameters of the drillstring determined using the process of Figure 2;
- Figure 8 shows a GUI displaying more parameters of the drillstring determined using the process of Figure 2;
- Figure 9 (a) to (h) show cross-sectional views of the wellbore, including a cuttings bed, during a variety of drillstring manipulations;
- Figure 10 (a) to (d) show plots of normal accelerations and lateral positions of a section (section 5) of the drillstring derived using the process of Figure 2;
- Figure 11 (a) to (d) show plots equivalent to those of Figure 10 but for a section of the drillstring further downhole than that used to derive Figure 10 (e.g. section 6);
- Figure 12 (a) to (d) show plots equivalent to those of Figure 10 when the wellbore is built to 80° to the vertical;
- Figure 13 shows movements and velocities of the drillstring shown in Figure 1 whilst being subject to induced lateral movements (ILM) involving rapid pulls in which the bottom hole assembly moves by more than a threshold amount;
- ILM induced lateral movements
- Figure 14 shows normal accelerations and lateral movements of the drillstring shown in Figure 1 at 30°, 45° and 60° inclination to the vertical when the drillstring is being subject to ILM involving rapid pulls in which the bottom hole assembly moves by more than a threshold amount;
- Figure 15 is a torque and drag plot for a wellbore, calculated using the process of Figure 2;
- Figure 16 shows a GUI view displaying results of a simulation
- Figure 17 shows a GUI view displaying determined parameters based on the results of the simulation shown in Figure 16;
- Figure 18 shows results of processing field data using the simulation.
- Drilling operations are often the most expensive cost in developing oil fields.
- down time is typically estimated to between 30 to 50 percent of the total operation time.
- down time during drilling operations, particularly deviated drilling operations can represent a sizable cost burden. Systems and procedures that can potentially reduce down time are therefore highly desirable.
- Models of the drillstring typically using finite element analyses, have been proposed, but achieving a practical, working modelling for use in the field is challenging.
- the model is based on a multi-dimensional lumped element model that described coupled axial and torsional movements of the drillstring.
- the model can also account for both static and dynamic Coulomb forces.
- the model makes the assumption that the non-linear and coupled terms in the set of equations can be modelled as a Taylor expansion with respect to time, within the length of a given time step. The state of the drillstring at the end of this time step is then solved analytically. This significantly reduces computational time and is numerically robust.
- the model is very fast and ideally suited for performing large or complex drillstring analyses or providing real time operating feedback and control of drilling operations using the modelled drillstring.
- the model can allow for better interpretation of field data and resultant control of the block position or hoist operations for lifting and lowering operations of the drillstring, rotary speed of a rotation unit such as a top drive or Kelly drive for rotating the drillstring, amongst other possibilities.
- the model can also provide quicker or earlier alarms or alerts when the operation is problematic.
- the model based system can be retrofitted for use with existing equipment that is already in place and leverages the data available from those systems to provide additional data and information regarding the drillstring.
- the speed of the model can allow it to provide such additional data dynamically and in real time, making “on the fly” operation possible.
- Also described herein is a cleaning operation for cleaning wellbores during drilling operations.
- a bed of cuttings or other debris tends to preferentially lie on a lower side in a lower half of the wellbore in a vertical cross section through the segment of wellbore relative to the upper side in an upper half of the wellbore in a vertical cross section through the segment of wellbore.
- the cleaning operation can potentially be performed without the model
- the model can be used in conjunction with the hole cleaning operation to significantly improve the implementation of cleaning operation, for example by identifying when various cleaning operations should be implemented and to which parts of the drillstring, based on, amongst other factors, a determination of whether particular sections of the drillstring lie on the upper or lower side of the wellbore.
- FIG. 1 shows a simplified schematic of a drilling arrangement 5.
- the drilling arrangement 5 comprises a drillstring 10 supported by a derrick 15.
- the derrick 15 is located on the surface and the drillstring 10 extends from the derrick 15 down into an underground formation 20.
- the drillstring 10 extends into a wellbore 25 that, in this example, is a deviated well in the form of a ‘J’ well. That is, the wellbore 25 extends vertically before transitioning through a bend towards the horizontal. At least parts of the drillstring 10 may deviate from the centre of the wellbore.
- a downhole end of the drillstring 10 is provided with a bottomhole assembly 27 that in turn comprises a drill bit 28 for drilling through the formation 20.
- the drillstring 10 can be any conventional drillstring 10 and generally comprises a linear series of connected elongate hollow pipe sections.
- the drilling arrangement 5 further comprises a hoist 30 for raising and lowering the drillstring 10 and a rotation mechanism 35 for rotating the drillstring 10.
- the hoist 30 as illustrated comprises a crown block 37 and motor driven draw-works 38 for driving a cable 39 that supports the drillstring 10 through the crown block 37, as is known in the art but the hoist could instead be or comprise a hydraulic or other suitable hoist. Indeed, a hydraulic hoist may be beneficial in providing more accurate hookload measurements, which are used by the model as described below.
- the rotation mechanism 35 is shown as a top drive, it will be appreciated that other suitable types of rotation mechanisms such as Kelly drives and the like may be used.
- the operation of components of the drilling arrangement 5, such as the hoist 30, the rotation mechanism 35 and the draw-works 38, is controlled by a controller 40. Potential control paths from the controller 40 to the components of the drilling arrangement 5 are shown using dashed lines.
- the controller 40 comprises a processor 45, data storage 50 and a user interface 55.
- the controller 40 is communicatively linked to the components of the drilling arrangement, such as the hoist 30, rotation mechanism 35 and draw-works 38, to control operation of those components.
- the user interface 55 is configured to allow an operator to interact with the controller and could optionally comprise output devices such as a screen, touchscreen, audible output devices such as speakers, visual output devices such as warning lights, and/or haptic output devices such as vibration units, and input devices such as a touchscreen, keyboard, roller ball, buttons, joystick, light pen and the like.
- the controller 40 could simply communicate with an external remote device, such as a user device, server or other remote computer system that provides the user interface 55, e.g. over the internet, a cellular or other wireless network, over a cabled connection, and/or the like.
- drilling arrangement 5 many features of the drilling arrangement 5, such as but not limited to, a mud system including a mud pump and reservoir, a suspended travelling block on which the top drive 35 is mounted, Blow Out Preventors (BOPs), the drill floor, pipe stands and the like, have been omitted from Figure 1 purely to improve clarity and a skilled person would appreciate that these and other conventional features would be present in the drilling system 5.
- BOPs Blow Out Preventors
- drilling arrangement 5 would be apparent to a skilled person, with the drillstring 10 being lowered into the wellbore and selectively rotated to rotate the drill bit 28 to drill through the formation 20, whilst mud is circulated down through the hollow drillstring 10 and back up to surface via an annulus between the drillstring 10 and casing in order to circulate drill cuttings and the like.
- drilling arrangement could use a downhole motor, or pump, or hydraulic features such as vanes or the like to drive the drill bit.
- Figure 1 shows a land rig, but the drilling rig may be any conventional rig type, including floating structures such as, but not limited to, semi-submersibles, drillship and tension leg platforms.
- either the controller 40 can be configured to implement a modelling system 60 or the controller may be in communication with a separate processing device that is configured to implement the modelling system 60, wherein the controller 40 can send data collected from sensors in the drilling arrangement 5 and/or operational data representing the operation of the drilling arrangement 5, such as settings set by the controller 40, to the modelling system 60.
- the modelling system 60 is configured to run software that causes it to implement a model 70 (see Figures 3 and 4) of the drillstring 10.
- the model can be configured using static data describing properties of the drillstring 10 and/or dynamic data received from the controller 40, such as operational data and settings from the controller 40 and/or measurement data from the sensors of the drilling assembly 5, and process it to determine further properties or parameters of the drillstring 10, in use.
- the modelling system 60 may comprise one or more processing devices that contain at least one processor, data storage and communication / networking capability and could be embodied in a personal computer, server, cloud based system, bespoke processing device, and/or the like.
- the software that causes the modelling system 60 to implement the model 70 is illustrated in Figure 2.
- the software comprises various functional modules 80 to 105 that are envisaged to be implemented together virtually by the software running on the modelling system but one or more of these functional modules could alternatively be implemented in separate hardware devices, e.g. as part of a distributed computing system.
- the modelling system 60 receives data 75 from one or more data sources 80 relating to the drilling arrangement 5, such as the measurement values from downhole and surface sensors (not shown), including sensors provided in the downhole assembly, and operational data and settings from the controller 40, and/or the like.
- data 75 is not limited to these and could also be obtained from databases or registers of drillstring and other equipment properties, online sources, manual input data, and/or the like.
- the input data 75 includes static data, that could be provided when initiating the software and comprises data such as non-varying properties of the drillstring 10.
- the input data also includes time-dependent data that is connected to a certain time.
- the input data 75 could come from a text file, a binary file, an external database, a live stream of data, or the like.
- the time-dependent data can be dynamically provided in real time or near real time / “on the fly” via a live feed from a sensor controller that receives or generates measurements from downhole and/or surface sensors and operating parameters of the drilling arrangement 5 from the controller 40, in use.
- the modelling system 60 is configured to parse the input data 75 into a format suitable for handling by the modelling system 60.
- the parsing could comprise converting mnemonics into canonical names and units, but is not limited to this. For instance, in a specific example, if a data variable for a block position has a name BLOCK_POS and has the unit “feet above the drill floor”, it is automatically renamed to a canonical name such as BPOS with units “meters above drill floor”. Completely erroneous data is also removed in the parser by comparison with set or predefined variable ranges. For example, a block position of 100 meters cannot be true, since no current drilling derrick is more than 100 meters tall.
- the output of time-dependent data from the data source 80 comprises one or more streams of time samples.
- Each time sample has a time tag and a list of variables with values, which may optionally have double precision.
- new variables can be added to the time samples.
- Some examples of time-dependent data that could be received include one or more of: top position (BPOS), depth (DMEA), depth of the drill bit 28 (DBTM), hookload (HKL), weight on the bit (WOB), torque at the surface (TRQ), rotary speed applied to the drillstring 10 (RPM), rate or volume of mud flow in (MFI) and/or stand pipe pressure (SPP), amongst other possibilities.
- the static data contains all data that is constant and relevant for running the software.
- the static data could include, for example, data describing one or more aspects of the geometry of the well, the specifications of all relevant equipment, such as the drillstring 10 itself, a bottom hole assembly, a drill bit, and/or the like, and materials such as drilling mud that may be used in the operation.
- the parsed data 75 from the one or more data sources 80 is stored in a database 85 that is stored in data storage accessible by the modelling system 60.
- the data storage could comprise local data storage such as a hard drive or SSD storage, and/or a remote server, cloud storage or network attached storage (NAS) or even be distributed between local and/or remote storage.
- the database 85 In addition to storing the parsed data 75, the database 85 also stores snapshots of the software execution. As shown in Figure 2, many of the software modules 85-100 implemented by the modelling system 60 have a state 85’-100’.
- the state 85’-100’ of each module 85-100 includes historic information that the respective module 85-100 requires to restart at a certain time instance.
- the states 85’-100’ of all modules 85-100 that have a state are stored in the database 85.
- This means that the database 85 can restart the software at any time/date snapshot that is stored. This arrangement effectively provides rollback functionality that involves starting at a prior time step. If the software is running in real time, it will catch up with real time as fast as possible.
- a rollback can be executed for several reasons. For instance, some new data points may conclude that previous assumptions have not been valid for a prior time. It is also important for security or reliance, e.g. in the event of a power shut down or similar.
- the activity code detector 90 comprises a state machine that detects what activity is occurring when the time-dependent data was collected, i.e. what activity the time-dependent data is associated with.
- the activity code detector 90 may be configured to identify activity logs or identifiers comprised in the data, detect patterns or signatures in the data that map to activities according to a pre-stored mapping, and/or the like. Examples of activities that could be detected by the activity code detector include one or more of: tripping in, tripping out, circulating, reaming, drilling, sliding, connection out, connection in, invalid data, and/or the like.
- the activities identified by the activity detector 90 may be used by the modelling system 60 to determine how to handle the associated data 75 in the subsequent modules 95, 100.
- the activity detector 90 may be configured to add messages to the data 75 identifying the activity associated with the time-dependent data 75 or indicating how the time-dependent data should be handled by the subsequent modules 95, 100. For example, invalid data is to be just passed through the subsequent modules 95, 100 without modification.
- the activity detector 90 can detect that a new pipe section is connected to or removed from the drillstring 10, with the consequence that the drillstring 10 is shorter or longer.
- the connection activity is determined by detecting when the block position has moved at least a set or pre-set distance, such as 8 meters, while the bit depth has remained constant.
- the reaming activity is determined when there is no connection, the bit is off bottom and rotation and flow speed are above some small thresholds.
- the circulating activity is the same as the reaming, when revolutions per minute (RPM) are below a RPM threshold.
- the tripping activity is the same as the circulating activity except the flow is off. Finally drilling is determined by when we reaming and on bottom.
- the input data 75 stored in the database 85 can be updated. Addition or removal of drillstring 10 pipe sections is typically detected after the connection or removal actually happened. In this case, the rollback functionality described above can be performed to roll back to when the connection actually happened to allow the change in drillstring 10 length to be correctly applied.
- the parsed data 75 is subjected to a data interpolator 95.
- the data interpolator 95 adds time samples in between the measured time samples.
- the interpolation by the data interpolator is required as the calculator modules 100 require a much higher time resolution for correct calculations.
- the modelling system 60 recalculates the model 70 repeatedly over short time steps, e.g. in the order of 10 2 to 10 5 ps, and beneficially in the order of 10 3 to 10 4 ps.
- the data 75 generally has a much slower collection rate, e.g. in the order of seconds.
- the provision of the data interpolator 95 allows the modelling system 60 to operate using “real world” data whilst maintaining the recalculation rate required for accuracy.
- the data interpolator 95 uses a Hermite cubic spline interpolator, where the derivative at the endpoints are matched, but the disclosure is not limited to this and it will be appreciated that other suitable interpolation methods may be used. Since the derivative of the current time sample is not known before the next time sample has arrived, this module stores some time samples back in time to perform better interpolation. Data points that result in extreme derivatives are omitted because this results in unrealistic drillstring vibrations.
- the data 75 for interpolation may have different resolutions. This situation is handled by postponing the release of time samples from the time-dependent data 75 to the calculator modules 100 that implement the model 70. Time samples that are released to the calculator modules 100 are guaranteed to contain all necessary variables at a user defined resolution. The only exceptions are time samples that are marked “only to be passed through”, such as invalid data. Some of the time dependent data may be interpolated and some may not, depending on the resolution. Examples of time dependent data 75 that is interpolated can include the rotary speed of drillstring 10 and the block position (BPOS or BLOCK POS). The data 75, interpolated where required to achieve the desired time resolution, is provided by the interpolator 95 to one or more calculator modules 100.
- the calculator module 100 performs calculations on the data 75 by inputting the data into the model 70 in order to recalculate the model for the time steps associated with the data 75.
- the recalculation of the model 70 for each time step by the calculator 100 is initiated by static parameters from the database 85.
- Each recalculation of the model 70 shares some common data (e.g. static data) and some data is particular for each recalculation.
- the common data could include, for example, the wellbore trajectory, the wellbore size, dimensions of pipe joints in the drillstring 10, rig related parameters and parameters related to model resolution.
- Specific parameters could be, for example, parameters related to drilling fluid rheology, wall friction coefficients and the like.
- the time- dependent data 75 received by the calculators 100 for recalculating the model 70 has the system resolution and contains meaningful data on all variables that are used in the calculations.
- the time-dependent data that arrives at the calculator 100 is handled based on messages from the activity detector 90.
- Some time-dependent data 75 is passed on through, other data 75 contains a message to change drillstring 10 length (i.e. a connection has just happened) and most time-dependent data is used to compute the next axial and rotational position of the drillstring 10.
- the outputs of the model 70 are time-dependent variables that are vectors. Each entry of these vectors represent the value of the variable at a certain depth. For instance, the last element of the drillstring 10 position is the position of the drill bit 28.
- the vectors are finally displayed in a drillstring display module that is part of a user interface 105.
- the output vectors calculated by the calculators 100 using the model 70 include, for example, one or more of: axial positions and velocities of the drillstring 10, rotary positions and velocities of the drillstring 10, tension forces on the drillstring 10, torques on the drillstring 10, normal forces on the drillstring 10, wall friction forces experienced by the drillstring 10, inclination of the drillstring 10 and/or the like.
- the calculator 100 uses the model 70 to determine indicators of one or more of: the parts of the drillstring 10 that are located on the upper side of the wellbore 25 and the parts of the drillstring 10 that are located on the low side of the wellbore 25, the parts of the drillstring 10 that are in open hole and the parts of the drillstring 10 that are in cased hole, the parts of the drillstring 10 that are sticking to the wellbore 25 and the parts of the drillstring 10 that are in slip condition and/or the like.
- the output vectors of the model 70 can be presented as graphs on the graphical user interface 105, wherein the graphs are displayed in a rolling time display (see Figures 5 to 8). These variables can include one or more of: calculated hookload, calculated torque and/or the like.
- the calculators 100 implement the model 70 to model the drillstring 10 in order to determine the required output vectors.
- the drillstring 10 is modelled as a set of n blocks 110a-n that are each connected to an adjacent block 110a-n by one of n springs 115a-n, as shown in Figures 3 and 4.
- the springs 115a-n are fixed to the blocks100a-n, meaning that the springs 115a-n can take up angular momentum.
- a three dimensional coordinate system is introduced.
- the first block 110a is hanging from the first spring 115a, which is attached to a point that is called the "block position".
- the heave motions are taken into account in Q(t), so that Q(t) is the veritcal movement of both the drillfloor and the top- drive movement with respect to the drillfloor.
- n normal vectors n which are basically the derivative of the tangent vectors with respect to arc length, as follows:
- each block 110a-n The mass centre of each block 110a-n is denoted X(t), where t is time.
- X,(t) X w (t) + hi(t)R(r ⁇ ⁇ )n, where X w (t) is always in the centre of the wellbore 25, hi(t) is the offset to the centre and R(n,) is a rotational matrix that is dependent on the lateral rotation of block / 110a-n, denoted by h ⁇ ).
- R(0) is equal to the two dimensional identity matrix.
- each block 110a-n is rotated clockwise around X,(t), with direction v by an angle q,( ⁇ ).
- the physical state of the drillstring at any time is therefore uniquely defined by the generalized coordinates q,(t), &,(t), q,-(t) and h,(t).
- the Euler-Lagrangian equation is given by: where H is the Lagrangian, R qj are the external forces, Re j are the external torques and /3 ⁇ 4 and are external torques and forces related to the other coordinates.
- the Lagrangian is given by the difference between kinetic and potential energy in the system, as follows:
- m is the mass and /, is the moment of inertia.
- k qj and kej are independent spring constants of the spring 115a-n above the respective block 110a-n.
- k n are the equivalent spring constants related to the bending moment of the drill pipe of the drillstring 10.
- the gravity constant is g
- BF is a buoyancy factor that is related to the hydro static pressure difference between the upper part and the lower part of an element (i.e. a weight 110a-n or spring 115a-n).
- the buoyancy factor BFi is equal to one, because there is no area that the pressure can act on. When the inclination is increasing, there is more area for the pressure to act on.
- the buoyancy factor is approximately 1 -p m /p s , where p m and p s are the densities of the mud and the steel, respectively.
- the curvature is likely to impact the buoyancy factor.
- buoyancy factors there are various techniques available in the art for estimating buoyancy factors for all elements. These buoyancy factors can be simulated separately without interfering with the rest of the model.
- BF, 1 -p m /p s is used. This definition ensures that a weight measurement at the top is correct.
- the model 70 implemented by the calculator modules 100 can be used to determine friction forces from the fluid.
- these can be determined using techniques known in the art, such as those given by Hovda in “semi-analytical models on axial motions of an oil-well dri listing in vertical wellbores", Journal of Sound and Vibrations, 417: 227-244 (2016), the contents of which are incorporated in their entirety by reference as if they were set out in full herein.
- the added mass due to friction acts on the bottom element (i.e.
- R is the radius of the wellbore 25
- L is the total length of the drillstring 25
- ct j is the fraction of the drillstring 10 radius at block
- the added mass is dependent on the tightness of the wellbore 25.
- the calculators 100 are configured to determine viscous forces using the model 70.
- the steady state viscous forces are the viscous forces when the acceleration is negligible.
- the viscous forces are equal to: where m is the viscosity of the mud and v,(V) is a constant term related to the flow speed of the pump V. For convenience, the term related to pump speed can be neglected.
- the acceleration of the mud is taken into account by the Basset forces in the above paper by Hovda et. al., but in this disclosure they are neglected.
- the Basset forces are, to some degree, incorporated by using a higher viscosity in the steady-state viscous forces. This simplifies this discussion substantially.
- the torque from steady state friction Re. ss .i is determined using an approach described in Hovda in “Automatic detection of abnormal torque while reaming", Journal of Petroleum Science and Engineering (2016) 177: 13-24, namely using: a ⁇ + a( CC
- the model 70 comprises a Coulomb friction model for determining normal forces.
- the friction force between two sliding surfaces is proportional to the normal force with a direction that opposes the motion.
- two surfaces stick together unless the force between the surfaces exceeds the normal force multiplied by the static friction coefficient.
- the Coulomb friction model is configured to determine the absolute values of the normal forces that are acting on the blocks 110a-n.
- the normal forces consist of essentially two components, namely gravity forces and tension / compression forces in curvatures.
- the calculators 100 are also configured to determine wall friction using the model 70.
- the friction between the wellbore 25 and the drillstring 10 is modelled as Coulomb friction.
- Coulomb friction For block /, there is a static Coulomb factor p s, , and a dynamic Coulomb factor m ⁇ ,.
- p s For block /, there is a static Coulomb factor p s, , and a dynamic Coulomb factor m ⁇ ,.
- the kinematic Coulomb friction on block / is:
- the friction forces can either be static or kinetic, which means that:
- Both the static and the dynamic Coulomb friction coefficients are dependent on whether the block 110a-n is in the casing or not. Moreover, if they are not inside the casing, the type of
- the forces on the drill bit 28 are estimated or measured.
- the forces acting on the drill bit 28 are the weight on the bit WOB and the torque on the bit TOB. These forces are only present when the drillstring 10 is drilling or sliding, otherwise they are zero.
- the weight on drill bit 28 is subtracted from R q,n and the torque on the bit is subtracted from R e,n ⁇ These forces can be taken b from downhole measurements if the drillstring contains wired / instrumented pipe containing appropriate sensors. Otherwise it can be estimated using any conventional drillstring model, depending on the type of bit.
- the model 70 includes an axial model.
- the equation above is developed into a system of n coupled second order ordinary differential equations.
- Mq + C q q + K q q f q (t), where all of the matrices are square of the size n x n and q is a vector of size n.
- M is a diagonal matrix with m, plus added mass on the diagonal
- C q is a diagonal matrix with c ss ,i on the diagonal
- the tridiagonal matrix K q is equal to:
- Ai is a diagonal matrix with a, on its diagonal and A is a tridiagonal matrix that is similar to K q , where the values of k qj are substituted by the values of a,.
- the parameter a is the cross section area of the /- th block
- the model 70 also includes a torsional model comprising torsional equations. These can be written in matrix form as:
- Equation (21) can be written as:
- the diagonal matrix Ji has /s on its diagonal and J2 is a tridiagonal matrix that is similar to K e , where the k e, s are substituted by the Ji s.
- the parameter J , ⁇ is the second moment of area of the pipe divided by/.
- the parameter / is the geometric mean of all
- the derivatives are given by: the convolutions / ⁇ (t) * t s l k j ( ) and / ⁇ (t) * t s l k j ( ) are solved analytically by demanding that / ⁇ is a polynomial.
- the outputs form the calculators 100 may be determined from the above models. 1105
- the axial positions and rotary speeds along the drillstring 10 are obviously represented by the q,s and the 0 j S.
- the calculated hookload is k q,i (Q - qi), while the downhole tension forces are calculated as k e,i (0i - Q M ) for 2 £ i £ n.
- the calculated surface torque is ke ,i ⁇ Q-di), while the downhole torques are
- the normal forces and the friction forces are the A/,s, the F? q,co,/ S and the R e,co,i s.
- / is a function of q, q, e, e,r and even other parameters as well.
- Dt is the time step that is in the range of 10 milliseconds or less.
- a temporary reduction in timestep may include when rotation is turned on and off.
- the model comprises a series of equations on a dimensionless scale of the form:
- the high side / low side indicator 165 indicates which parts of the drillstring 10 lie on the lower side of the wellbore 25 and which parts of the drillstring 10 lie on the upper side of the wellbore 25, when viewed in the lateral cross section of the wellbore in which the part of drillstring 10 is located. This indication of “upper side” or “lower side” is
- the open hole / cased hole indicator indicates which parts of the drillstring 10 are in the cased hole and which parts are in the open hole. Mathematically, each position is
- the stick / slip indicator indicates which parts of the drillstring 10 are moving and which parts are stalled in friction. This metric is calculated for a certain block /by checking are equal to zero or not.
- the inclination of the drillstring 10 is calculated from the inverse cosine of the geometry factor g ii .
- the above described model can be used by the calculators 100 to determine valuable properties of the drillstring 10, in use.
- the last module is a graphical user interface, GUI, 55,
- the user can choose what parameters to be shown and also a specific resolution for the GUI 55 that can be lower than the resolution of the calculator 100.
- the user can start and stop, replay and choose simulation speed if data is simulated or read from files.
- 1175 There are two display modules, a rolling time display 130 and a drillstring display 135.
- the rolling time display 130 is a time display where the screen is constantly rolling and new points are added on the bottom parts of the graphs. This displays drilling parameters determined by the modelling system 60 such as block position, depth, bit depth, drilling activity and more. There is a zoom mode, where the user can decide if he
- 1180 wants to zoom on time or on value for each graph.
- a graph is zoomed between its minimum (minus ten percent) and its maximum (plus ten percent).
- the zoom levels are also controlled by the fact that the min value for each variable can not be less or more than some certain values. The same is true for the max value.
- the user has the opportunity to see dots where data points exist and there is a mouse-over right
- the user can display any graph they want, provided that the graph is given by either the data provider or calculated by the software application.
- Graphs in the drillstring display 135 are not rolling as time goes by. They have a fixed size with one point per block in the model. This means that if the number of blocks
- the current time step is the default, but in the right click menu of points in the rolling time display, one can choose to show a different snapshot in the drillstring display 135.
- An activity graph 140 shows the activities in the operations of the drilling assembly 5, with different colours indicating different activities, as determined by the activity detector 90 of the modelling system 60. It can be seen in this example that the drillstring 10 is pulled out of the hole and that the hole is cleaned by either circulation or
- the drill bit 28 is also off bottom and rotation and mud circulation is on. This can be verified by visual inspection of the other graphs.
- the drillstring displays 135 to the right have depth along the drillstring 10 on the y-axis. These graphs are not rolling and are recalculated for every time step. On every time step, all values in all graphs are updated. The drillstring displays 135 are always
- the first graph of the drillstring displays 135 is an inclination of the drillstring 10 as a function of depth. When the drillstring 10 is on bottom, this is equal to the inclination of the wellbore.
- the two other graphs in the drillstring display 135 are the axial tensions and the drillstring torques.
- FIG. 1225 An example of a torque and drag plot is given in figure 15. This plot is for a j-well, similar to the wellbore 25 shown in Figure 1 , that starts to deviate from vertical after 800 meters and increases in angle until it is horizontal.
- the wellbore is 5000 meter long with a true vertical depth of 2600 meters. Flowever, these dimensions are simply given as an example and the disclosure is not limited to these.
- the model 70 that is described above
- the three curves 1510a, 1510b, 1510c shown on the left hand side of Figure 15 are calculated in the same way, with the only difference that the drillstring is run into the hole with constant speed.
- the middle curve 1515 in Figure 15 is the neutral weight, which
- the up weights are derived by noting the hookload when pulling out with constant speed and no rotation.
- the down weights are derived by noting the hookload when running in with constant speed and no rotation.
- the software 60 can be used, and by using the activity code detector 90 to find instances when up and down weights can be measured. Since the bit depth is also known, these up and down weights can beneficially be automatically detected and plotted in a common torque and drag plot, such as that shown in Figure 15.
- the model 70 that is described above in relation to the implementation of the calculator 100, takes into account transient effects and also the coupling between the
- An application of the modelling system 60 is to compute two estimates of
- the plots 145, 150, 155 of the GUI give additional information. For example, it can be seen that most of the drillstring 10 is in an inclined section of the wellbore 25, where it is located on the low side of the wellbore (see inclination 160 and “highside” 165 indicator plots in Figure 5). This is relevant information, since hole cleaning works best
- the use of the modelling system 60 described above is beneficial as it can be used to determine whether any given section of the drillstring 10 is at the top or bottom of the wellbore 25 when viewed in a cross sectional view through the wellbore 25, as detailed above. It can also be used to determine the rotational speed of the drillstring 10. Based on this information from the modelling system 60, an operator or automatic
- control unit can control the operation of the drilling arrangement 5 to alter the cleaning program, e.g. by lifting or lowering the drillstring 10 or adjusting the rotation of the drillstring 10 so that the drillstring 10 is moved to a different location in the cross section of the wellbore 25 or is changed into a different rotational condition.
- An example of a wellbore 25 cleaning procedure comprises controlling the
- the controlling of the drillstring 10 could comprise, for example, lifting or lowering the drillstring 10 and/or adjusting the tension on the drillstring 10, e.g. using the hoist 30.
- the operation of the cleaning procedure is dependent on one or more outputs of the modelling system 60.
- the outputs of the modelling system 60 are dependent on one or more outputs of the modelling system 60.
- 1345 system 60 could comprise one or more of: a position of the drillstring in the wellbore 25, an indication that one or more parts of the drillstring 10 are located upper side or lower side of the corresponding section of the wellbore and/or a determination by the modelling system 60 of a speed of rotation of the drillstring 10 at one or more parts of the wellbore 25 or a determination of whether the drillstring 10 is rotating or not rotating and/or sticking
- displaced cuttings can remain in the main flow channel to be carried along and/or from the wellbore 25.
- This technique can be called induced lateral movements (ILM) and can be used with or without rotation of the drillstring 10.
- 1360 lateral movements can be modelled using the modelling system 60 described above.
- initial conditions are determined. For example this could be that the blocks 110a-n are at rest but that the previous action was pulling the drillstring 10 in a direction that is associated with pulling it out of the wellbore 25; or the blocks 110a-n are at rest but that the previous action was inserting the drillstring 10 further into the
- induced lateral movements Three examples of the induced lateral movements (ILM) are presented.
- small axial movements e.g. pulling and lowering
- small axial movements e.g. pulling and lowering
- bottom hole assembly 27 moves by less than a threshold amount.
- a plurality of pulls and lowerings of the drillstring 10 e.g. rapid pulls and releases
- the repeated pulls and lowerings or releases are enough to move the bottom hole assembly 27 by more than a threshold amount, i.e. more than in the first example (small axial movements).
- Another example comprises inducing
- the modelling system 60 is configured to determine which sections of the drillstring 10 are located on an upper side of the wellbore 25 in cross section or on a lower side, based on the signs of the normal forces or accelerations with depth determined by the modelling system 60.
- a N i (r) Ni ( t)Inh , which is the normal force divided by the mass of the i-th block 110.
- the sign of a N i (r ) defines whether the segment of the drillstring 10 represented by the block 110 is located in the upper side or lower side of the wellbore 25.
- a N i (r) Ni ( t)Inh
- lateral movement of the i-th block 110 can also be defined as a function lat N i ( ), wich has a range equal to [0,lat max i ].
- lat max i is the maximum hole diameter subtracted by the diameter of the drillstring 10 at the depth of
- a first example of an initial condition is when the drillstring 10 is at rest but had
- a second example of an initial condition is when the drillstring 10 is at rest but was being run in prior to being at rest. This means that the positions of the blocks are
- a third example of an initial condition is when the drillstring 10 is at rest but was being rotated prior to being at rest. This means that the positions of the blocks are the same as if the drillstring 10 was previously rotated.
- v is considered to be constant. It has no effect on the temporal dynamics and therefore it is set to zero for simplicity.
- the outlined model allows the static and the dynamic Coulomb friction coefficients to vary anywhere along the drillstring 10, they are set to 0.4 and 0.3, respectively.
- a third method is to use harmonic axial movements with rotation. This allows the drillstring 10 to occasionally be forced into the cuttings bed
- the difference in drillstring positions for the three initial conditions can be investigated.
- q(0) which is used to compute ⁇ 1 ⁇ 2 , ;( 0). Since every i corresponds to a certain depth, a N i ( 0) can be used to create a
- Figure 10(a) shows the variation of normal acceleration with depth for the J-well deviated wellbore 25 shown in Figure 1.
- Figures 10(b) to 10(d) show the variation in lateral position of the drillstring 10 along its length when an initial condition has been pulling out of the well, reaming and running into the well, respectively.
- drillstring 10 lies in the lower side of the wellbore 25 all the way up to the point at which the wellbore lies at 30° from vertical while reaming. This suggests that the critical region can be cleaned well by using rotation. That is, for regions where the drillstring 10 is determined by the modelling system 60 to lie in the lower side of the corresponding section of the wellbore 25, rotation of the drillstring 10 may be the most effective cleaning
- ILM of the drillstring 10 may be the most effective cleaning regime.
- the modelling system 60 may be configured to define one or more ranges of orientations associated with specific cleaning processes, e.g. based on the determination of whether the drillstring 10 is located in the upper or lower side of an associated section of the wellbore 25, based on a determination of whether the drillstring 10 is sticking or sliding, based on a determination of axial or angular speed or
- Figure 11 (a) to (d) shows similar plots to Figure 10(a) to (d) but for the sixth and last (furthest downhole) section of the drillstring 10. If Figure 11 (b) is compared with Figure 10(b), it can be seen that the drillstring 10 can be lifted from the cuttings bed 200 at approximately the same depth, i.e. by the fourth casing shoe. On one hand, the longer
- the rapid pull procedure is one that results in the bottom hole assembly 27 being moved by more than a threshold amount. This may result in larger ranges of ILM motion that may reach the cuttings bed 200 in sections of
- the extent of the ILM motion that is applied can be dependent on the orientation of the wellbore 25 determined by the modelling system 60 using the model 70, e.g. the amplitude of the lateral vibrations can be increased with increasing orientation angle, at least up to a maximum orientation
- Modelling of this operation can use driving-forces that have the shape of a piecewise polynomial as follows:
- the accelerations anywhere in the drillstring 10 will be a sum of square waves, one traveling upwards and one traveling downwards.
- the period of the square waves are 2p/wi in the dimensionless timescale.
- the first eigenfrequency 6 oi is about 30 percent lower when a heavy bottomhole assembly 27 is present.
- the dashed line is the movement of the first block, which is approximately the same as the movement of Q( ).
- both N ) and N,6 I( ' t) are always positive, meaning that the drillstring 10 will constantly be positioned at the upper part of the wellbore.
- Figure 14(c) where the lateral movements are plotted.
- N T) starts out negative, but
- the modelling system 60 can also beneficially support well operations that use the drillstring 10 other than wellbore cleaning. For example, during operations such as reaming and tripping operations, being able to efficiently lower the drillstring 10 onto the bottom of the wellbore while causing a minimum of axial vibrations is beneficial.
- operations such as reaming and tripping operations
- being able to efficiently lower the drillstring 10 onto the bottom of the wellbore while causing a minimum of axial vibrations is beneficial.
- the modelling system 60 can be used to determine and optionally control how axial and torsional movements are
- Figure 7 shows a simulation of how to optimally start rotation.
- the modelling system 60 is used with a driving-force that has the shape of a piecewise polynomial as follows:
- T 3CC is equal to the period of the first torsional eigenfrequency. It can be seen in Figure 7 that very small vibrations are present. This can be used to avoid stick-slip effects that are common when the crew is tripping too fast or when rotation is turned on too fast.
- the modelling system 60 can beneficially be used on floating drilling rigs to calculate a minimal rotation speed that is needed, in order to minimize surge and swab pressures that are consequences of heave motions. 1605
- the modelling system 60 is not limited to the above examples and can be used to determine a range of parameters relating to the drillstring 10 and/or in a range of applications.
- the weight on (drill)bit , WOB, and torque on (drill)bit, TOB are useful input parameters for the modelling system. If downhole components such as the
- WOB and TOB are instrumented with suitable sensors, then measurements of WOB and TOB can be made directly. Alternatively or additionally, WOB and TOB can be estimated from data collected at the surface or estimated entirely using a model.
- the WOB can be calculated from the total
- hookload which is the total force on the hook, i.e. the weight of the drillstring 10, and any equipment attached to the drillstring 10, less by any force that acts to reduce that weight. It will be appreciated that the hookload can be determined from measurements made above surface. The total hookload T HKL can be found by measuring the hookload in a situation when the drill bit 28 is just off the bottom of the well with constant rotation of the
- the hookload can be determined by the modelling system 60 using the model 70.
- T HKL HKL - TR HKL
- TR HKL is a transient hookload that is the difference between the current modelled hookload and the modelled hookload when rotary speed and block position is kept constant for a long time.
- a transient torque TR TRQ is the difference between the current modelled torque and the modelled torque when rotary speed and block position are kept constant. If rotary speed is adjusted while drilling, the total torque must be adjusted according to a new TR TRQ. The determined
- WOB and TOB are coupled and a variety of bit rock models exist, depending on the bit type that is used. For example, a model described for PDC bits in Besselink et al. “A semi-analytical study of stick-slip oscillations in drilling
- the weight on the drill bit 28 is assumed to be the sum of cutting forces W c and friction forces W f .
- the torque on bit is assumed to be the sum of a torque relating to cutting T c and a torque related to friction T f .
- W c n ⁇ a ed nb (t , where n b is the number of blades of the bit, z a is a
- the widths of the wearflats are l nb .
- 1675 is of high interest for finding resonant frequencies.
- the unknown is the intrinsic specific energy, which is basically referred to the hardness of the rock. It may be very difficult to predict this parameter if we take into account these high axial vibrations. An improved way of modelling this can be applied, which removes this high frequency coupling and allows
- Another example use of the modelling system 60 comprises an alternative method for determining parameters such as, but not limited to, intrinsic specific energy,
- Real hole depth (DEPTH CALC) is defined as the maximum of real bit depth (BIT DEPTH CALC). Solving a drilling criterion (i.e.
- BIT DEPTH CALC DEPTH CALC (i.e. the real hole depth).
- the weight on bit (WOB) is assumed to comprise only the cutting forces and is
- the modification may comprise adding 2pK ⁇ a e/q h , to the last diagonal element of C q in the equation given in the “Axial Model” section above ( This calculation has been found to be more robust than calculating WOB explicitly and adding it to f Q n .
- One way to estimate the surface weight on bit involves computing the total hookload T HKL.
- the algorithm involves trying different e(depth ) curves and estimating the difference between SWOB and SWOB CALC over fixed time spans (AT).
- the algorithm effectively tests different linear coefficients until
- the snapshot and the rollback functionality described elsewhere in the present disclosure is used actively in the estimation of e (depth), and the above is one possible way to implement this.
- the rollback functionality brings a real benefit to these calculations as when SWOB CALC is wrong, then DEPTH CALC must also be wrong.
- the only stable way to catch up with the correct depth is to go back and simulate with a softer or a harder formation.
- the choice of the rollback time span AT can, in examples, be related to rock strength divided by drillstring stiffness.
- Figures 16 to 18 illustrate an exemplary simulation using the above techniques.
- the drillstring in this example is initially 3997 meters long and for simplicity it has a uniform pipe size, i.e. no bottom hole assembly.
- the pipe size in this example is 5 inches in diameter with a cross-sectional area of 0.0032m 2 .
- the drilling mud has density 1 .0 Sg.
- We assume a rake angle of 20 degrees and taking the sine of that we obtain z a 0.34202.
- n 30 and a
- the drillstring initially hangs of its own weight and, due to tension, the drillbit 28 is only a foot above bottom. Rotation is first turned up to 200RPM and after approximately half a minute, the bit 28 is lowered onto the bottom. After a short acceleration period the block speed becomes constant at 36 m/hour and stays like this
- the downhole ROP is not the same as the top side ROP.
- the ROP_CALC is the downhole ROP and this is derived from q n .
- the 1 - exp(-t/T) form is evident in ROP_CALC, where T is the halving time.
- FIG. 1805 difference between SWOB and SWOB CALC.
- Figure 17 shows the result of the detection algorithm, where the curves are the same as the ones defined in Figure 16. It can be seen in Figure 17 that the MSE CALC is close to the true MSE, which is denoted by @T_MSE. The system allows for curves to be plotted on a depth scale to the right.
- system used as a drillstring simulator can be run on off line field
- MSE CALC has the appearance of being more smoothed than MSES.
- the main difference is that MSE CALC is not smoothed and spatial resolution is not lost, which will be the case if the MSES results are smoothed.
- real drill bit depth (R DBTM) real well depth (R DEPTH) calculated using the modelling system 60.
- ROP rate of penetration
- the parameters determined from the techniques can be applied to known bit-rock interaction models such as the one described in Besselink et al. “A semi- analytical study of stick-slip oscillations in drilling systems” Journal of Computational and Nonlinear Dynamics 6: 1-9 (2011), the contents of which are incorporated by reference as if set out in full herein. In this case, it is possible to identify a procedure to start drilling
- Torque and drag of the drillstring during drilling can be calculated in real time using the models 70 identified above. Torque and drag plots can be made automatically. Moreover, since additional information is available from the model 70, other plots that
- wear characteristics of all pipe joints that make up the drillstring 10 are known or at least can be estimated, and this list of wear characteristics can be updated at any time. If a tool provider is consistently using this software application, wear characteristics can be maintained for their drillstring tool set. The wear characteristics can be for instance the
- An estimated replacement time can be determined by comparing the determined compression and/or torsional force cycles with the wear characteristics and a suitable alert raised or controller 40 automatically controlled.
- the modelling system 60 can be used to automatically detect when something abnormal happens, such as maxed out torque, top drive stall-outs and over-pulls and more. This may be achieved by running pattern recognition algorithms on parameters of the drillstring 10 in use, as determined by the modelling system 60.
- the pattern recognition may involve the use of trained artificial intelligence techniques, such
- This technique may be used to raise an alarm or alert, e.g. for operators performing the operations using the drillstring 10, or to take automatic preventative action, e.g. via integration with an automated control system such as the NOVOS platform.
- the models may be used to raise an alarm or alert, e.g. for operators performing the operations using the drillstring 10, or to take automatic preventative action, e.g. via integration with an automated control system such as the NOVOS platform.
- Detection of lateral vibrations is another field that the modelling system 60 can provide further information.
- the mathematical framework given above describes lateral vibrations. Detection of forward, backward and chaotic whirl can be integrated into the models 70.
- processors suitable for the execution of a computer program include CPUs and microprocessors, and any one or more processors. Generally, a processor will receive instructions and data from
- a read-only memory or a random access memory or both The essential elements of a computer are a processor for executing instructions and one or more memory devices for storing instructions and data.
- a computer will also include, or be operatively coupled to receive data from or transfer data to, or both, one or more mass storage devices for storing data, e.g., magnetic, magneto-optical disks, or optical disks.
- Information carriers suitable for embodying computer program instructions and data include all forms of non-volatile memory, including by way of example semiconductor memory devices, e.g. EPROM, EEPROM, and flash memory devices; magnetic disks, e.g., internal hard disks or removable disks; magneto-optical disks; and CD-ROM and DVD-ROM disks.
- semiconductor memory devices e.g. EPROM, EEPROM, and flash memory devices
- magnetic disks e.g., internal hard disks or removable disks
- magneto-optical disks e.g., CD-ROM and DVD-ROM disks.
- the processor and the memory can be supplemented by, or
- the invention can be implemented on a device having a screen, e.g., a CRT (cathode ray tube), plasma, LED (light emitting diode) or LCD (liquid crystal display) monitor, for displaying information to the user and an input device, e.g., a keyboard, touch screen, a mouse, a trackball, and the like by
- a screen e.g., a CRT (cathode ray tube), plasma, LED (light emitting diode) or LCD (liquid crystal display) monitor
- an input device e.g., a keyboard, touch screen, a mouse, a trackball, and the like
- feedback provided to the user can be any form of sensory feedback, e.g., visual feedback, auditory feedback, or tactile feedback; and input from the user can be received in any form, including acoustic, speech, or tactile input.
Abstract
Description
Claims
Priority Applications (5)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GB2212402.8A GB2607536B (en) | 2020-02-27 | 2021-02-25 | Determination of drillstring parameters and associated control |
US17/802,282 US20230151725A1 (en) | 2020-02-27 | 2021-02-25 | Determination of Drillstring Parameters and Associated Control |
CA3169074A CA3169074A1 (en) | 2020-02-27 | 2021-02-25 | Determination of drillstring parameters and associated control |
BR112022017161A BR112022017161A2 (en) | 2020-02-27 | 2021-02-25 | METHODS FOR MODELING A DRILLING COLUMN IN A WELL HOLE AND FOR CLEANING A WELL HOLE, SYSTEM, AND, COMPUTER PROGRAM PRODUCT |
NO20220988A NO20220988A1 (en) | 2020-02-27 | 2021-02-25 | Determination of drillstring parameters and associated control |
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CN113391373A (en) * | 2021-05-10 | 2021-09-14 | 三明学院 | Young modulus calculation method, device, equipment and storage medium |
CN115822551A (en) * | 2022-09-15 | 2023-03-21 | 中国石油天然气集团有限公司 | Method, apparatus, device and storage medium for determining downhole weight-on-bit and torque |
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CN114352191B (en) * | 2022-01-11 | 2023-11-21 | 北京三一智造科技有限公司 | Stratum weakening pretreatment method and pore-forming method |
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CN115822551A (en) * | 2022-09-15 | 2023-03-21 | 中国石油天然气集团有限公司 | Method, apparatus, device and storage medium for determining downhole weight-on-bit and torque |
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US20230151725A1 (en) | 2023-05-18 |
GB2607536A (en) | 2022-12-07 |
GB202002753D0 (en) | 2020-04-15 |
NO20220988A1 (en) | 2022-09-16 |
CA3169074A1 (en) | 2021-09-02 |
GB202212402D0 (en) | 2022-10-12 |
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BR112022017161A2 (en) | 2022-10-11 |
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